Use of carbon dioxide generated by hydropyrolysis for process inertization

ABSTRACT

A hydropyrolysis process comprises feeding both (i) hydrogen and (ii) a biomass-containing feedstock or a biomass-derived feedstock, to a hydropyrolysis reactor vessel. The process comprises producing a CO 2 -containing vapor stream and at least one liquid product. A CO 2  product, separated from the CO 2 -containing vapor stream, is advantageously used for at least one inertization function of the hydropyrolysis process. Representative inertization functions include operation of solids transport equipment, blanketing of liquid containers, drying of biomass-containing feedstock or biomass-derived feedstock, conveying or separating solids, and combinations thereof. Importantly, CO 2  products utilized for these inertization functions may be obtained predominantly, if not completely (depending on the nature of the feedstock), from renewable carbon in biomass.

FIELD OF THE INVENTION

The disclosure is directed to using carbon dioxide generated by ahydropyrolysis process as an inert gas to sustain one or more, andpossibly all, inertization needs of the hydropyrolysis process.

BACKGROUND

Biomass refers to biological material derived from living or deceasedorganisms and includes lignocellulosic materials (e.g., wood), vegetableoils, carbohydrates (e.g., sugars), aquatic materials (e.g., algae,aquatic plants, and seaweed), and animal by-products and wastes (e.g.,offal, fats, and sewage sludge). In the conventional pyrolysis ofbiomass, typically fast pyrolysis carried out in an inert atmosphere, adense, acidic, reactive liquid bio-oil product is obtained, whichcontains water, oils, and char formed during the process. Much of theoxygen present in biomass ultimately resides in the bio-oil, therebyincreasing its chemical reactivity.

Characteristic total acid numbers (TAN) of conventional bio-oil are inthe range of 100-200, rendering it highly corrosive. Moreover, thisproduct tends to undergo polymerization, is generally incompatible withpetroleum hydrocarbons due to water miscibility and very high oxygencontent (on the order of about 40% by weight), and has a low heatingvalue. The unstable bio-oils of conventional pyrolysis tend to thickenover time and can also react to a point where hydrophilic andhydrophobic phases form. As a result, transportation and utilization ofthis product are problematic. Also, it is difficult to upgrade thisproduct to a liquid hydrocarbon fuel, due to the retrograde reactionsthat typically occur in conventional pyrolysis processes, including fastpyrolysis. Dilution with methanol or other alcohols has been shown toreduce the activity and viscosity of the formed bio-oils, but thisapproach is not considered practical or economically viable, due to thelarge amounts of unrecoverable alcohol that are required to stabilizepyrolysis liquids. The removal of char, generated by conventionalpyrolysis, from the liquid pyrolysis product while it is still in thevapor phase presents an additional technical challenge. Significantamounts of oxygen and free radicals in the pyrolysis vapors remainhighly reactive and form a pitch-like material upon contact with charparticles on the surface of a filter or other solid separator.Consequently, devices used to separate char from the hot pyrolysisvapors can become quickly plugged, due to the reactions of char andpyrolysis vapor constituents that occur on and within the layer of charon the surfaces of such devices, as well as within the pores of porousfilter elements. Finally, it is noted that the upgrading of pyrolysisoils, using conventional hydroconversion processes, consumes largequantities of H₂, and extreme process conditions, including highhydrogen pressures needed to meet product quality requirements, makesuch processes uneconomical. The reactions are inherently out of balancein that, due to the high pressures required, too much water is createdwhile too much H₂ is consumed. In addition, conventional hydroconversionreactors can rapidly develop high pressure differentials, due toreactive coke precursors present in the pyrolysis oils or from cokeproduced as a result of catalysis.

More recently, the use of hydrogen in biomass pyrolysis (i.e.,hydropyrolysis) has been disclosed. For example, hydropyrolysisprocesses taught in U.S. Pat. No. 8,492,600 have been found to overcomea number of the drawbacks of conventional fast pyrolysis processes,including those described above, and have led to a number of otherprocessing advantages. Despite these and other improvements, the art ofhydropyrolysis is continually seeking further advancements in terms ofprocess economics, as well as the overall carbon footprint associatedwith the production of biofuel end products, e.g., based on a lifecycleassessment of their greenhouse gas (GHG) emissions. Such advancementsare of significant importance in establishing competitiveness, in termsof both cost and product quality, with conventional petroleum refiningprocesses.

SUMMARY

In accordance with aspects of the disclosure, a hydropyrolysis processcomprises feeding both (i) hydrogen and (ii) a biomass-containingfeedstock or a biomass-derived feedstock (e.g., a pretreated feedstockderived from a biomass-containing feedstock, following devolatilizationand/or hydropyrolysis) to a hydropyrolysis reactor vessel. The processcomprises producing a CO₂-containing vapor stream and at least oneliquid product. The process comprises using a CO₂ product, separatedfrom the CO₂-containing vapor stream, for at least one inertizationfunction of the hydropyrolysis process, with representative inertizationfunctions being described more fully below.

Unlike conventional pyrolysis processes for the production of bio-oilsfrom renewable feedstocks such as lignocellulosic materials,“hydropyrolysis” is accompanied by hydrodeoxygenation and, as such,involves the use of hydrogen under elevated operating pressures.Therefore, the safe operation of hydropyrolysis processes is of primaryimportance, as even small leaks, which might not pose a cause forconcern in conventional pyrolysis, may present a potential fire orexplosion hazard in hydropyrolysis. In addressing the safety needsrequired for making hydropyrolysis a commercial reality, it has now beenfound that considerable quantities and flow rates of inert gas aretypically needed for various inertization functions associated with theprocess, in order to reduce or eliminate risks of fire and/or explosion,or otherwise comply with safety regulations applicable to the site ofoperation. Such inertization functions include (i) operation of solidstransport equipment, such as lock hoppers for conveying particulatesolids, (ii) blanketing of liquid containers, (iii) drying ofbiomass-containing or biomass-derived feedstock, and/or (iv) conveyingand/or separating solids via a flowing gas stream.

Conventionally, inert gases such as high-purity nitrogen and/or argonare widely recognized for their ability to provide needed inertizationfunctions and effectively address risks of fire and explosion. However,the provision of such gases from external sources represents not only anadded raw materials cost, but also an increase in the overall GHGemissions associated with production of higher value liquids, such ashydrocarbon-containing biofuel end products and blending components. Thelatter drawback is a result of the conventional energy requirements(e.g., electricity from coal combustion) associated with the productionof inert gases at high purity, for example using low temperaturedistillation or membrane separation.

Advantageously, aspects of the disclosure relate to the discovery thatcarbon dioxide (CO₂) generated in the hydropyrolysis process itself canserve as a readily available inert gas for one or more, and preferablyall, of the inertization functions described above. In this manner, theneed and associated costs for importing inert gases may be reduced oreliminated altogether. Importantly, the CO₂ utilized for these functionsis obtained predominantly, if not completely (depending on the nature ofthe feedstock), from renewable carbon in biomass. Therefore, unlike theuse of conventional inert gases, the use of such “internal” CO₂ does notadd to the carbon footprint of the higher value liquids as describedherein (e.g., hydrocarbon-containing biofuels), based on a lifecycleassessment (LCA) of their GHG emissions.

Embodiments relate to hydropyrolysis processes comprising feeding both(i) hydrogen and (ii) a biomass-containing feedstock or abiomass-derived feedstock, to a hydropyrolysis reactor vessel. ACO₂-containing vapor stream and at least one liquid product areproduced, and a CO₂ product, separated from the CO₂-containing vaporstream, may be used for at least one inertization function of thehydropyrolysis process. The inertization function may be selected fromthe group consisting of operation of solids transport equipment,blanketing of liquid containers, drying of biomass-containing orbiomass-derived feedstock, conveying and/or separating solids, andcombinations thereof.

According to particular embodiments, the CO₂-containing vapor stream,from which the CO₂ product is separated, may be selected from the groupconsisting of (i) a hydropyrolysis reactor vapor, obtained from ahydropyrolysis reactor output, (ii) a hydroconversion zone output, (iii)a pre-reactor vapor stream or a purified pre-reactor vapor stream, and(iv) a regeneration effluent or a hydrogasification effluent.

In further embodiments, the hydropyrolysis process may further comprisewithdrawing a hydropyrolysis reactor output from the hydropyrolysisreactor vessel; feeding a hydropyrolysis reactor vapor, obtained fromthe hydropyrolysis reactor output following the removal of substantiallyall char particles, to a hydroconversion reactor vessel; hydroconvertingat least a portion of the hydropyrolysis reactor vapor in ahydroconversion zone to obtain a hydroconversion zone output;recovering, by condensing a substantially fully deoxygenated hydrocarbonliquid (and optionally a separate, or phase-separable aqueous phasehydroconversion product) from the hydroconversion zone output, ahydroconversion gaseous mixture; and introducing at least a portion ofthe hydroconversion gaseous mixture to a steam reformer that provides anet production of CO₂, in addition to a net production of hydrogen, in asteam reformer effluent. In this case, the CO₂-containing vapor streammay be the steam reformer effluent, and the CO₂ product may be recoveredas a CO₂-enriched product of separation from the steam reformereffluent.

In other embodiments, one or more CO₂ products, separated fromCO₂-containing vapor streams and used for any of the inertizationfunctions described herein, comprise CO₂ derived from renewable carbonof the biomass-containing or biomass-derived feedstock. According tospecific embodiments, such CO₂ product(s) comprise CO₂ derivedexclusively from renewable carbon of the biomass-containing orbiomass-derived feedstock. For example, such CO₂ product(s) may compriseCO₂ derived from at least one transformation of the biomass-containingor biomass-derived feedstock or of further processed, carbonaceousproducts of these feedstocks (e.g., coke or carbon that may accumulateon a catalyst or solid bed material as described in greater detailbelow, or otherwise char), with the transformation being selected fromthe group consisting of hydropyrolysis, devolatilization, andcombustion.

The above and other aspects, features and advantages of the presentdisclosure will be apparent from the following detailed description ofthe illustrated embodiments thereof which are to be read in connectionwith the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the exemplary embodiments of thepresent disclosure and the advantages thereof may be acquired byreferring to the following description in consideration of theaccompanying figures, in which the same reference numbers, or referencenumbers in which the last two digits are the same indicate like featuresand wherein:

FIG. 1 is a schematic flow diagram of a system, including a steamreformer, a separation apparatus, and a carbon dioxide manifold inaccordance with one embodiment of the disclosure;

FIG. 2 is a schematic flow diagram, including the system of FIG. 1, alock hopper, and a hydropyrolysis reactor, according to one embodimentof this disclosure;

FIG. 3 is a schematic flow diagram, including the system of FIG. 1, apre-reactor, and a hydropyrolysis reactor, according to anotherembodiment of this disclosure;

FIG. 4 is a schematic flow diagram, including the system of FIG. 1, apre-reactor and a hydropyrolysis reactor, according to anotherembodiment of this disclosure; and

FIG. 5 is a schematic flow diagram, including the system of FIG. 1,which is integrated into a hydropyrolysis process including ahydroconversion reactor.

FIGS. 1-5 should be understood to present an illustration of thedisclosure and/or principles involved. Simplified process flow schemesare used, in order to facilitate explanation and understanding. Detailsincluding pumps, heaters and some heat exchangers, valves,instrumentation, and other items not essential to the understanding ofthe disclosure are not shown. As is readily apparent to one of skill inthe art having knowledge of the present disclosure, methods forproviding hydroprocessed biofuels according to various other embodimentsof the disclosure, will have configurations and components determined,in part, by their specific use.

DETAILED DESCRIPTION

Hydropyrolysis Processes and Vapor Streams Comprising CO₂

Hydropyrolysis processes include a hydropyrolyzing step that occurs in ahydropyrolysis reactor vessel containing hydrogen and a deoxygenatingcatalyst. A representative hydropyrolyzing step is described, forexample, in U.S. Pat. No. 8,492,600. Hydropyrolysis involves, generally,feeding both hydrogen and a biomass-containing feedstock and/or abiomass-derived feedstock to a hydropyrolysis reactor vessel operatingat elevated temperature and pressure. One or more CO₂-containing vaporstreams are generated as a result, typically in conjunction at least oneliquid product, such as a hydropyrolysis bio-oil and/or other “highervalue liquids,” which refer to liquid products having a greater value(e.g., on a weight basis) than the biomass-containing or biomass-derivedfeedstock, or combination thereof. Representative higher value liquidsinclude individual compounds (e.g., levoglucosan), classes of compounds(e.g., aromatic hydrocarbons), and mixtures of compounds suitable for aparticular purpose (e.g., gasoline or diesel fuel boiling-rangehydrocarbons suitable for use as transportation fuels or otherwiseblending into such fuels).

“Biomass” refers to substances derived from organisms living above theearth's surface or within the earth's oceans, rivers, and/or lakes.Representative biomass can include any plant material, or mixture ofplant materials, such as a hardwood (e.g., whitewood), a softwood, ahardwood or softwood bark, lignin, algae, and/or lemna (sea weeds).Energy crops, or otherwise agricultural residues (e.g., loggingresidues) or other types of plant wastes or plant-derived wastes, mayalso be used as plant materials. Specific exemplary plant materialsinclude corn fiber, corn stover, and sugar cane bagasse, in addition to“on-purpose” energy crops such as switchgrass, miscanthus, and algae.Short rotation forestry products, such as energy crops, include alder,ash, southern beech, birch, eucalyptus, poplar, willow, paper mulberry,Australian Blackwood, sycamore, and varieties of paulownia elongate.Other examples of suitable biomass include vegetable oils, carbohydrates(e.g., sugars), organic waste materials, such as waste paper,construction, demolition wastes, and biosludge.

A “biomass-containing” feedstock may comprise all or substantially allbiomass, but may also contain non-biological materials (e.g., materialsderived from petroleum, such as plastics, or materials derived fromminerals extracted from the earth, such as metals and metal oxides,including glass). An example of a “biomass-containing” feedstock thatmay comprise one or more non-biological materials is municipal solidwaste (MSW).

“Biomass-derived,” for example when used in the phrase “biomass-derivedfeedstock,” refers to products resulting or obtained from the thermaland/or chemical transformation of biomass, as defined above, orbiomass-containing feedstocks (e.g., MSW). Representativebiomass-derived feedstocks therefore include, but are not limited to,products of pyrolysis (e.g., bio-oils), torrefaction (e.g., torrefiedand optionally densified wood), hydrothermal carbonization (e.g.,biomass that is pretreated and densified by acid hydrolysis in hot,compressed water), and polymerization (e.g., organic polymers derivedfrom plant monomers). Other specific examples of biomass-derivedproducts (e.g., for use as feedstocks) include black liquor, purelignin, and lignin sulfonate. Biomass-derived feedstocks also extend topretreated feedstocks that result or are obtained from thermal and/orchemical transformation, prior to, or upstream of, their use asfeedstocks for a given conversion step (e.g., hydropyrolysis). Specifictypes of pretreating steps that result in biomass-derived productsinclude those as described herein, and particularly those occurring in apre-reactor, upstream of a hydropyrolysis reactor, and involvingdevolatilization and/or at least some hydropyrolysis of abiomass-containing feedstock. Therefore, certain pretreated feedstocksare also “biomass-derived” feedstocks, whereas other pretreatedfeedstocks, for example resulting or obtained from classificationwithout thermal or chemical transformation, are “biomass-containing”feedstocks, but not “biomass-derived” feedstocks.

It is therefore also possible to feed to the hydropyrolysis reactorvessel, in place of all or a portion of the biomass-containingfeedstock, a biomass-derived feedstock, such as a pretreated feedstockthat is obtained from a biomass-containing feedstock, after having beendevolatilized and/or partially hydropyrolyzed in a pretreating reactor(pre-reactor), upstream of the hydropyrolysis reactor vessel, asdescribed herein. Such pre-reactor thermal and/or chemicaltransformations of biomass may be accompanied by other, supplementaltransformations, for example to reduce corrosive species content, reducehydropyrolysis catalyst poison content (e.g., reduced sodium), and/or areduce hydroconversion catalyst poison content. Devolatilization and/orpartial hydropyrolysis of biomass or a biomass-containing feedstock in apre-reactor may be carried out in the presence of a suitable solid bedmaterial, for example a pretreating catalyst, a sorbent, a heat transfermedium, and mixtures thereof, to aid in effecting such supplementaltransformations and thereby improve the quality of the pretreatedfeedstock. Suitable solid bed materials include those having dual ormultiple functions. In the case of a pretreating catalyst, those havingactivity for hydroprocessing of the biomass-containing feedstock,described below, are representative.

It is also possible to feed a biomass-containing feedstock that is apretreated feedstock, obtained after having been subjected to apretreating step, for example a physical classification to improve atleast one characteristic, such as a reduced non-biological materialcontent (e.g., content of glass, metals, and metallic oxides, includingall mineral forms), a reduced average particle size, a reduced averageparticle aerodynamic diameter, an increased average particle surfacearea to mass ratio, or a more uniform particle size.

In the case of a pretreated feedstock having been devolatilized and/orpartially hydropyrolyzed, the vapors obtained from a pre-reactor, i.e.,a pre-reactor vapor stream or purified pre-reactor vapor stream obtainedfollowing the removal of solids (e.g., char or solid bed material, suchas catalyst) may be fed to the hydropyrolysis reactor vessel. Accordingto some embodiments, depending on the particular operation of thepre-reactor, it may be possible to cool and condense a pretreated liquidproduct from the pre-reactor vapor or purified pre-reactor vapor, fromwhich a pretreatment gaseous mixture may be separated. The pretreatmentgaseous mixture, in this case, comprises CO₂ and at least one othernon-condensable gas (e.g., H₂, CO, and/or CH₄). At least a portion ofseparated pretreatment gaseous mixture may be introduced to a steamreformer that provides a net production of CO₂, in addition to a netproduction of hydrogen that may be recycled to the hydropyrolysisprocess to satisfy some or all of its hydrogen requirements. This steamreformer may be, but is not necessarily, the same as that describedbelow, for use in providing a net production of hydrogen from aseparated hydroconversion gaseous mixture. As described below, the steamreformer effluent (output from steam reformer), or a portion thereof,may be enriched in hydrogen (e.g., by selective removal of CO₂ and/orother gases) using additional separation equipment, for example amembrane separation unit or a pressure swing adsorption (PSA) unit, toprovide a high purity hydrogen-containing gas stream for recycle to thehydropyrolysis process. This, in turn, allows for the recovery of aCO₂-enriched product of separation from the steam reformer effluent.

Whether or not pretreated liquid is condensed, the pre-reactor vaporstream or purified pre-reactor vapor stream, obtained from thepre-reactor, may contain hydrogen, if hydrogen is utilized initially tocarry out devolatilization and/or limited hydropyrolysis in thepre-reactor. Therefore, the pre-reactor vapor stream, or purifiedpre-reactor vapor stream, may provide some or all of the hydrogen thatis fed to the hydropyrolysis reactor, or at least some, and possiblyall, of the chemical hydrogen requirement for hydropyrolysis.

Hydropyrolysis produces a hydropyrolysis reactor output comprising atleast one non-condensable gas, a partially deoxygenated hydropyrolysisproduct (e.g., in the form of a condensable vapor) and solid charparticles. In many cases, the hydropyrolysis reactor output willcomprise, in addition to CO₂, at least one other non-condensable gas(e.g., H₂, CO, and/or CH₄). However, depending on the methanationactivity and water-gas shift conversion activity of the deoxygenatingcatalyst, more or less methane (CH₄) will be produced at the expense ofCO, CO₂, and H₂. As used herein, the “partially deoxygenatedhydropyrolysis product” of the hydropyrolyzing step may compriseoxygenated hydrocarbons (e.g., derived from cellulose, hemicellulose,and/or lignin) that may be subjected to more complete deoxygenation(e.g., to produce hydrocarbons and remove the oxygen in the form of CO,CO₂, and/or water) in a subsequent (downstream) hydroconversion process.The term “partially deoxygenated hydropyrolysis product,” however, doesnot preclude the presence of some amount of hydrocarbons (e.g., aromatichydrocarbons such as alkylbenzenes) that are fully deoxygenated and thuscannot be further deoxygenated.

The hydropyrolysis reactor vessel, as in the case of an upstream,pre-reactor vessel, may contain a fluidized bed of deoxygenatingcatalyst. The fluidizing gas for the hydropyrolysis reactor vessel maycomprise hydrogen present in a hydrogen-containing hydropyrolysis feedstream and/or possibly a purified pre-reactor vapor stream, either orboth of which may be fed to this vessel. Following the hydropyrolyzingstep, representative processes may further comprise removing all orsubstantially all of the char particles and/or other solid particles(e.g., catalyst fines) from the hydropyrolysis reactor output to providea hydropyrolysis reactor vapor having a reduced char content. Theremoval of char particles, such as those which may be entrained in thehydropyrolysis reactor output, may be particularly important inprocesses in which the products of hydropyrolysis, including thehydropyrolysis reactor vapor or a portion thereof, are subjected to afixed bed catalytic conversion process. According to some embodiments,it may be possible to cool and condense the hydropyrolysis reactorvapor, in order to recover a hydropyrolysis bio-oil product (andoptionally a separate, or phase-separable aqueous phase hydropyrolysisproduct), from which a hydropyrolysis gaseous mixture may be separated.The hydropyrolysis bio-oil product may be further treated or reacted(e.g., for further deoxygenation), or otherwise used directly as an endproduct, for example as a liquid fuel blending component. Thehydropyrolysis gaseous mixture comprises CO₂ and at least one othernon-condensable gas (e.g., H₂, CO, and/or CH₄).

At least a portion of separated hydropyrolysis gaseous mixture may beintroduced to a steam reformer that provides a net production of CO₂, inaddition to a net production of hydrogen that may be recycled to thehydropyrolysis process to satisfy some or all of its hydrogenrequirements. This steam reformer may be, but it not necessarily, thesame as that described below, for use in providing a net production ofhydrogen from a separated hydroconversion gaseous mixture. As describedbelow, the steam reformer effluent (output from steam reformer), or aportion thereof, may be enriched in hydrogen (e.g., by selective removalof CO₂ and/or other gases) using additional separation equipment, forexample a membrane separation unit or a pressure swing adsorption (PSA)unit, to provide a high purity hydrogen-containing gas stream forrecycle to the hydropyrolysis process. This, in turn, allows for therecovery of a CO₂-enriched product of separation from the steam reformereffluent.

Representative processes may further comprise hydroconverting,preferably without intermediate condensation of a hydropyrolysis bio-oilproduct, at least a portion of the hydropyrolysis reactor vapor (e.g.,obtained following the removal of solid char particles as describedabove) in a hydroconversion zone. The hydroconversion zone may compriseone or more hydroconversion reactor vessels downstream of thehydropyrolysis reactor vessel. The one or more hydroconversion reactorvessels of the hydroconversion zone contain hydrogen and ahydroconversion catalyst, which is normally present as a fixed bed. Theconditions of elevated hydrogen pressure, elevated temperature, and theuse of hydroconversion catalyst are sufficient to further deoxygenate,and in many cases substantially fully deoxygenate, the partiallydeoxygenated hydropyrolysis product in the hydropyrolysis reactor vapor.The hydrogen required for this further deoxygenation, and fed to thehydroconversion zone, may be present in the hydropyrolysis reactor vaporand/or possibly an additional hydrogen-containing hydroconversion feedstream, which may be fed separately or combined with the hydropyrolysisreactor vapor.

A hydroconversion zone output (i.e., the effluent from thehydroconversion reactor(s) of the hydroconversion zone) contains agaseous mixture including CO₂ and at least one other non-condensable gas(e.g., H₂, CO, and/or CH₄), in addition to vapors that may be condensedinto product liquids. In particular, the hydroconversion zone output canbe cooled prior to, or within, a separation zone (e.g., comprising oneor more stages of separation, possibly at differing temperatures and/orpressures), which allows for vapor-liquid phase separation of thecomponents of this stream, and possibly also aqueous-organic phaseseparation of the condensed product liquids. For example, an aqueousphase hydroconversion product may comprise water condensed from thehydroconversion zone output and an organic phase hydroconversion productmay comprise a substantially fully deoxygenated hydrocarbon liquid.

From the separation zone, therefore, a substantially fully deoxygenatedhydrocarbon liquid may be recovered as a condensed fraction or liquidphase, and a hydroconversion gaseous mixture may be removed as anon-condensed fraction or vapor phase. At least a portion of separatedhydroconversion gaseous mixture may be introduced to a steam reformerthat provides a net production of CO₂, in addition to a net productionof hydrogen that may be recycled to the hydropyrolysis process tosatisfy some or all of its hydrogen requirements. According to oneembodiment, the steam reformer effluent (output from steam reformer), ora portion thereof, may be enriched in hydrogen (e.g., by selectiveremoval of CO₂ and/or other gases) using additional separationequipment, for example a membrane separation unit or a pressure swingadsorption (PSA) unit, to provide a high purity hydrogen-containing gasstream for recycle to the hydropyrolysis process. This, in turn, allowsfor the recovery of a CO₂-enriched product of separation from the steamreformer effluent. In addition, substantially fully deoxygenatedhydrocarbon liquid may be fractionated, as described above, usingfurther separation equipment, for example a distillation column orseries of distillation columns, to obtain substantially fullydeoxygenated higher value liquid products such as gasoline boiling-rangeand/or diesel fuel boiling-range hydrocarbon fractions.

Suitable catalysts for use in the pre-reactor vessel (if used),hydropyrolysis reactor vessel, and/or hydroconversion reactor vessel (ifused) will in general have activity for hydroprocessing of thebiomass-containing feedstock, biomass-derived feedstock (e.g., apretreated feedstock), and/or their hydropyrolysis reaction products, inan environment of suitable hydrogen partial pressure, temperature, andother conditions as described herein. Hydroprocessing is meant toencompass broadly a number of possible reactions, includinghydrotreating, hydrocracking, hydroisomerization, and combinationsthereof, as well as possible oligomerization occurring in ahydrogen-rich environment. Representative hydroprocessing catalystsinclude those comprising at least one Group VIII metal, such as iron,cobalt, and nickel (e.g., cobalt and/or nickel) and at least one GroupVI metal, such as molybdenum and tungsten, on a high surface areasupport material such as a refractory inorganic oxide (e.g., silica,alumina, titania, and/or zirconia). A carbon support may also be used.

Following a period of extended use, catalyst or other solid bed materialmay accumulate coke, carbon, or other materials (e.g., melted plastic)that is detrimental to the functioning of the catalyst or solid bedmaterial for its intended purpose. Catalyst or other solid bed materialhaving accumulated deposits may be withdrawn from any of the pre-reactorvessel, hydropyrolysis reactor vessel, and/or hydroconversion reactorvessel(s), for example incidentally as entrained particles in the vaporstreams exiting these reactor vessels, or otherwise deliberately fromthe solid beds within these reactor vessels (e.g., fluidized particlebeds within the pre-reactor vessel and/or hydropyrolysis reactor vessel,or fixed particle beds within the hydroconversion reactor vessel(s)). Inthe case of withdrawing the catalyst and/or other solid bed materialfrom within particle beds, this may be carried out using a solidsdrawoff outlet exiting the particle bed. Any withdrawn catalyst or othersolid bed material may be separated from unwanted solids (e.g., charparticles) in a fraction enriched in the catalyst or other solid bedmaterial, for example by using a separation based on density, andreturned to their respective reactor vessels.

Prior to this return of any withdrawn catalyst or other solid bedmaterial, or any fraction enriched in these solids, however, suchwithdrawn catalyst, withdrawn other solid bed material, or enrichedfraction(s) thereof, may be subjected to conditions under whichaccumulated coke, carbon, or other accumulated materials, are removed.Representative conditions include oxidizing conditions sufficient toregenerate the catalyst or other solid bed material, by removing theaccumulated coke and carbon by combustion, as well as reducingconditions (e.g., in the presence of a flowing hydrogen-containing gas)sufficient to hydrogasify the accumulated coke and carbon, convertingthese contaminants to methane and other light hydrocarbons.Hydrogasification of withdrawn catalyst, in a hydrogasification vessel,may be accompanied by sulfiding of this catalyst, for example byintroducing H₂S or a suitable H₂S precursor into the hydrogen-containinggas. The regeneration of catalyst or other solid bed material, in aregeneration vessel, results in a regeneration effluent comprising CO₂and at least one other non-condensable gas (e.g., H₂, CO, and/or CH₄).Likewise, the hydrogasification of catalyst or other solid bed materialresults in a hydrogasification effluent comprising CO₂ and at least oneother non-condensable gas (e.g., H₂, CO, and/or CH₄).

Conditions in the hydropyrolysis reactor include a temperature generallyfrom about 300° C. to about 600° C., typically from about 400° C. toabout 500° C., and often from about 410° C. to about 475° C. The weighthourly space velocity (WHSV) in the hydropyrolysis reactor, calculatedas the weight flow rate of the biomass-containing feedstock orbiomass-derived feedstock, divided by the weight of the catalystinventory in the hydropyrolysis reactor vessel, is generally from about0.1 hr⁻¹ to about 10 hr⁻¹, typically from about 0.5 hr⁻¹ to about 5hr⁻¹, and often from about 0.8 hr⁻¹ to about 2 hr⁻¹. Conditions in thehydroconversion reactor (or any of possibly two or more hydroconversionreactors, if used) include a temperature generally from about 200° C. toabout 475° C., typically from about 260° C. to about 450° C., and oftenfrom about 315° C. to about 430° C. The weight hourly space velocity(WHSV) of the hydroconversion reactor, calculated as the weight flowrate of the feed to the hydroconversion reactor (e.g., a purified vaporstream obtained from the hydropyrolysis reactor, following the removalof char particles) divided by the weight of the catalyst inventory ofthe hydroconversion reactor vessel, is generally from about 0.01 hr⁻¹ toabout 5 hr⁻¹, typically from about 0.05 hr⁻¹ to about 5 hr⁻¹, and oftenfrom about 0.1 hr⁻¹ to about 4 hr⁻¹.

Regeneration conditions sufficient to combust accumulated coke and otheraccumulated deposits are known in the art and include a regenerationtemperature generally in the range from about 400° C. to about 750° C.in an oxygen-containing environment. Hydrogasification conditionssufficient to form methane and other hydrocarbons from accumulated cokeand other accumulated deposits are known in the art and include ahydrogasification temperature generally in the range from about 500° C.to about 950° C. Both regeneration and hydrogasification may beperformed at substantially atmospheric pressure or slightly aboveatmospheric pressure (e.g., less than about 3 bar above atmosphericpressure).

Due to the diverse functions of the pre-reactor (if used), operatingconditions in the pre-reactor may vary broadly and may include theranges of temperatures and pressures described above with respect to thehydropyrolysis reactor. However, higher and lower temperatures arecontemplated for some embodiments, for example representativetemperatures may range generally from about 150° C. to about 650° C.,and typically from about 260° C. to about 540° C., depending on thespecific objective(s) of the pretreating step. Also, due to thesignificant extent of deoxygenation in the hydropyrolysis reactor vesseland optional hydroconversion reactor vessel, the associatedhydropyrolyzing and hydroconverting steps are normally both exothermic,i.e., the reactions associated with these steps involve a net generationof heat, despite the pyrolysis reactions in isolation being endothermic.In contrast, due to the relatively low extent of hydroconversion (or insome cases no hydroconversion), occurring in the pre-reactor vessel, thepre-reactor operation is generally endothermic, i.e., the reactions inthe pre-reactor overall involve a net consumption of heat.

Separation of CO₂ Products for Inertization Functions

As discussed above, CO₂ products, obtained from the hydropyrolysisprocess, can serve as a readily available inert gas for one or more, andpreferably all, of the inertization functions required of the process.These functions include (i) operation of solids transport equipment(e.g., lock hoppers and solids transfer screws) for the transport ofsolids, including biomass and/or solid bed materials such as catalyst,both to and from one or more reactors, as described above; (ii)blanketing of liquid containers (e.g., at ambient pressure orsuperatmospheric pressure), including flammable, hydrocarbon-containingand oxygenated hydrocarbon-containing intermediate and final products ofhydropyrolysis; (iii) drying of biomass, and/or (iv) conveying solidsvia a flowing gas stream, both to and from one or more reactor vessels,as described herein, and/or separating solids using a flowing gasstream.

Representative CO₂ products that are used for the inertization functionsdescribed above may be separated from vapors generated by hydropyrolysisand, in particular, those CO₂-containing vapor streams, as set forth inthe process description above. For example, representative vaporstreams, from which CO₂ may be separated, include (i) the hydropyrolysisreactor vapor stream, preferably obtained from a hydropyrolysis reactoroutput and following the removal of solid char particles from thisoutput, (ii) a hydroconversion zone output, if one or morehydroconversion reactor vessels are included downstream of thehydropyrolysis reactor, (iii) a pretreating reactor (pre-reactor) vaporstream or a purified pre-reactor vapor stream that is preferablyobtained following the removal of solids (e.g., char or solid bedmaterial, such as catalyst) from the pre-reactor vapor stream, if apre-reactor is included upstream of the hydropyrolysis reactor and/or(iv) a regeneration effluent or a hydrogasification effluent, ifregeneration or hydrogasification of solid bed material, such ascatalyst, used in a pre-reactor, the hydropyrolysis reactor, or ahydroconversion reactor, is included in the hydropyrolysis process.Regarding vapor streams (i) and (iii), the removal of solid charparticles from the hydropyrolysis reactor output and/or the removal ofsolids from the pre-reactor vapor stream may be performed by filtrationor centrifugation (e.g., using cyclones), either internal to, orexternal to, the respective hydropyrolysis reactor vessel or pre-reactorvessel. In the case of a regeneration effluent or hydrogasificationeffluent, such streams may be used as CO₂ products, without separationfrom their parent CO₂-containing vapor streams.

The designation of a CO₂ product as being “separated from” a givenhydropyrolysis process stream (e.g., any of the CO₂-containing vaporstreams as described above) refers to CO₂, which is recovered in the CO₂product, originating from that process stream. The CO₂ product may beenriched in CO₂, relative to the concentration in the stream from whichthe CO₂ originated. Otherwise, the CO₂ product may have a CO₂concentration that is substantially the same as that in the stream fromwhich the CO₂ originated. The designation of being “separated from” doesnot preclude the use of prior operations that may or may not affect thegas concentration of the designated hydropyrolysis process stream fromwhich the CO₂ is separated. Such prior operations include intermediateseparations of the hydropyrolysis process stream (with or withoutenrichment of the CO₂ concentration), intermediate reactions (e.g.,steam reforming or water-gas shift) performed on the hydropyrolysisprocess stream, and/or intermediate mixing of the hydropyrolysis processstream (which may or may not result in enrichment of the CO₂concentration). According to some embodiments, however, any of the CO₂products described herein may be separated from their designatedhydropyrolysis process streams (i) without intermediate separation, (ii)without intermediate reaction, and/or (iii) without intermediate mixing.

In the case of separation of CO₂ from the hydropyrolysis reactor vapor,according to one embodiment, this vapor may be cooled to condense ahydropyrolysis bio-oil product (and optionally a separate, orphase-separable aqueous phase hydropyrolysis product), from whichhydropyrolysis gaseous mixture may be separated, comprising CO₂ and atleast one other non-condensable gas (e.g., H₂, CO, and/or CH₄), and,depending on the separation conditions (e.g., temperature, pressure, andnumber of theoretical equilibrium separation stages) possibly one ormore condensable vapors such as water vapor, and vapors of a partiallydeoxygenated product. The CO₂ product used for one or more of theinertization functions may therefore be the hydropyrolysis gaseousmixture or a CO₂-enriched product of separation from the hydropyrolysisgaseous mixture. In this case, the designation “CO₂-enriched” refers tothe product having a higher CO₂ concentration than the hydropyrolysisgaseous mixture. The CO₂-enriched product of separation from thehydropyrolysis gaseous mixture may, according to specific embodiments,be the product of a gas separation selected from a membrane-basedseparation, an adsorbent-based separation (e.g., pressure-swingadsorption (PSA) or temperature swing adsorption (TSA)), a solvent-basedseparation (e.g., using a chemical solvent such as an amine or ahydroxide (caustic), or otherwise using a physical solvent such asSelexol®), or a combination thereof. The CO₂ product separated from thehydropyrolysis reactor vapor may, according to more specificembodiments, be a CO₂-enriched product of separation from a steamreformer effluent. This effluent stream may be, but it not necessarily,the same as that described below, obtained as the output of steamreforming to provide a net production of hydrogen from a separatedhydroconversion gaseous mixture.

In the case of separation of CO₂ from a hydroconversion zone output,according to one embodiment, this vapor may be cooled to condense highervalue liquid products such as gasoline boiling-range and/or diesel fuelboiling-range hydrocarbon-containing fractions, from which ahydroconversion gaseous mixture may be separated, comprising CO₂ and atleast one other non-condensable gas (e.g., H₂, CO, and/or CH₄), and,depending on the separation conditions (e.g., temperature, pressure, andnumber of theoretical equilibrium separation stages) possibly one ormore condensable vapors such as water vapor, and vapors of asubstantially fully deoxygenated product. The CO₂ product used for oneor more of the inertization functions may therefore be thehydroconversion gaseous mixture or a CO₂-enriched product of separationfrom the hydroconversion gaseous mixture. In this case, the designation“CO₂-enriched” refers to the product having a higher CO₂ concentrationthan the hydroconversion gaseous mixture. The CO₂-enriched product ofseparation from the hydroconversion gaseous mixture may, according tospecific embodiments, be the product of a gas separation selected from amembrane-based separation, an adsorbent-based separation (e.g.,pressure-swing adsorption (PSA) or temperature swing adsorption (TSA)),a solvent-based separation (e.g., using a chemical solvent such as anamine or a hydroxide (caustic), or otherwise using a physical solventsuch as Selexol®), or a combination thereof.

According to a representative embodiment, therefore, CO₂ that is usedfor one or more inertization functions is separated from ahydroconversion zone output, and may, in particular, be a CO₂-enrichedproduct of separation from the hydroconversion gaseous mixture. In sucha case, according to a preferred embodiment, the hydroconversion gaseousmixture may contain hydrocarbons, including non-condensable hydrocarbons(e.g., methane, ethane, ethylene) and/or condensable hydrocarbons (e.g.,propane, propylene, butanes, and/or butenes) and may be fed to a steamreformer to reform or convert the hydrocarbons to carbon monoxide (CO)and hydrogen. An accompanying water-gas shift reaction may furtherconvert the produced carbon monoxide to CO₂ and additional (reformed)hydrogen. Therefore, the steam reformer effluent may be enriched in bothCO₂ and hydrogen, relative to the hydroconversion gaseous mixture. TheCO₂ product separated from the hydroconversion zone output may thereforebe, more specifically, a CO₂-enriched product of separation from thesteam reformer effluent. In this case, the designation “CO₂-enriched”refers to the product having a higher CO₂ concentration than the steamreformer effluent (and also a higher CO₂ concentration than thehydroconversion gaseous mixture). The CO₂-enriched product of separationfrom the steam reformer effluent may, according to specific embodiments,be the product of a gas separation selected from a membrane-basedseparation, an adsorbent-based separation (e.g., pressure-swingadsorption (PSA) or temperature swing adsorption (TSA)), a solvent-basedseparation (e.g., using a chemical solvent such as an amine or ahydroxide (caustic), or otherwise using a physical solvent such asSelexol®), or a combination thereof. According to a preferredembodiment, the CO₂-enriched product of separation from the steamreformer effluent is obtained by PSA, which may also produce ahydrogen-enriched product that may be recycled for use in the process,such as in a pre-reactor, the hydropyrolysis reactor, or ahydroconversion zone.

In the case of separation of CO₂ from a pretreating reactor(pre-reactor) vapor stream or a purified pre-reactor vapor stream,according to one embodiment, either of these vapor streams may be cooledto condense a pretreated liquid product (and optionally a separate, orphase-separable aqueous phase pretreated product), from which apretreatment gaseous mixture may be separated, comprising CO₂ and atleast one other non-condensable gas (e.g., H₂, CO, and/or CH₄), and,depending on the separation conditions (e.g., temperature, pressure, andnumber of theoretical equilibrium separation stages) possibly one ormore condensable vapors such as water vapor, and vapors of adeoxygenated product of devolatilization. The CO₂ product used for oneor more of the inertization functions may therefore be the pretreatmentgaseous mixture or a CO₂-enriched product of separation from thepretreatment gaseous mixture. In this case, the designation“CO₂-enriched” refers to the product having a higher CO₂ concentrationthan the pretreatment gaseous mixture. The CO₂-enriched product ofseparation from the pretreatment gaseous mixture may, according tospecific embodiments, be the product of a gas separation selected from amembrane-based separation, an adsorbent-based separation (e.g.,pressure-swing adsorption (PSA) or temperature swing adsorption (TSA)),a solvent-based separation (e.g., using a chemical solvent such as anamine or a hydroxide (caustic), or otherwise using a physical solventsuch as Selexol®), or a combination thereof. The CO₂ product separatedfrom the pre-reactor vapor stream or a purified pre-reactor vapor streammay also be a CO₂-enriched product of separation from a steam reformereffluent. This effluent stream may be, but it not necessarily, the sameas that described below, obtained as the output of steam reforming toprovide a net production of hydrogen from a separated hydroconversiongaseous mixture.

In the case of separation of CO₂ from a regeneration effluent or ahydrogasification effluent, according to one embodiment, this vapor maybe treated (e.g., by filtration or centrifugation (using cyclones)) forthe removal of a solids-enriched stream, from which a regenerationgaseous mixture or a hydrogasification gaseous mixture may be separated,comprising CO₂ and one or more products of combustion orhydrogasification of deposits (e.g., coke) formed on a catalyst or othersolid bed material as described herein. The CO₂ product used for one ormore of the inertization functions may therefore be the regenerationgaseous mixture or hydrogasification gaseous mixture, or otherwise aCO₂-enriched product of separation from the regeneration gaseous mixtureor hydrogasification gaseous mixture. In this case, the designation“CO₂-enriched” refers to the product having a higher CO₂ concentrationthan the regeneration gaseous mixture or hydrogasification gaseousmixture, respectively. The CO₂-enriched product of separation from theregeneration gaseous mixture or hydrogasification gaseous mixture may,according to specific embodiments, be the product of a gas separationselected from a membrane-based separation, an adsorbent-based separation(e.g., pressure-swing adsorption (PSA) or temperature swing adsorption(TSA)), a solvent-based separation (e.g., using a chemical solvent suchas an amine or a hydroxide (caustic), or otherwise using a physicalsolvent such as Selexol®), or a combination thereof.

As is apparent from the above description, including the designation ofproducts used for inertization functions as being “CO₂-enriched,” it isnot necessary that pure CO₂ be used, and in fact the CO₂ product(s) usedmay contain impurities and even combustible gases (e.g., H₂, CO, andgaseous hydrocarbons such as methane and ethane) in amounts that do notsubstantially adversely impact the ability of these CO₂ products toachieve the necessary protection from fire and/or explosion hazards.Advantageously, by using CO₂ products having impurities, according tosome embodiments, the further costs associated with obtaining higherlevels of purity for these products are avoided. In representativeembodiments, combustible gases may be present in concentrations up tothose in which, upon mixture of the CO₂ product with air in anyproportion, either (A) the concentration of oxygen is below the limitingoxygen concentration (LOC), which is namely the maximum oxygenconcentration at which combustion is not possible, regardless of theconcentrations of the combustible gases, when in the same proportions asin the CO₂ product (providing a specific “fuel” mixture), or (B) theconcentrations of the combustible gases are below the lower explosivelimit (LEL) for the combustible gases, when in the same proportions asin the CO₂ product (providing a specific “fuel” mixture). According tofurther embodiments, for an added margin of safety, the combustiblegases may be present in concentrations up to 90%, or up to 80%, of theconcentrations (in the same proportions) at which either the conditions(A) or (B) above apply when the CO₂ product is mixed with air in anyproportion.

According to particular embodiments, a CO₂ product used for one or moreof the inertization functions described herein has, independently or incombination, a hydrogen concentration and/or a CO concentration ofgenerally less than about 7% by volume, typically less than about 3% byvolume, and often less than about 1% by volume. According to otherembodiments, a CO₂ product may additionally, or alternatively, have atotal hydrocarbon concentration of generally less than about 3% byvolume, typically less than about 1% by volume, and often less thanabout 0.1% by volume. The total concentration of combustible gases, or,alternatively, the combined concentrations of H₂, CO, and hydrocarbons,is generally less than about 10% by volume, typically less than about 5%by volume, and often less than about 1% by volume. In some cases, asubstantially pure CO₂ product may be used, having a CO₂ purity ofgenerally at least about 98% by volume, typically at least about 99% byvolume, and often at least about 99.5% by volume.

According to yet further embodiments, the CO₂ products that are used forthe inertization functions may be separated from CO₂-containing vaporstreams generated from hydropyrolysis, as described above, and mayfurther include an inert gas such as nitrogen, or a mixture of inertgases, which is not generated from hydropyrolysis. According to someparticular embodiments, the inert gas(es) may be present in an amountsuch that the concentrations of the combustible gases are below themaximum concentrations, below 90% of the maximum concentrations (in thesame proportions), or below 80% of the maximum concentrations (in thesame proportions) at which, upon mixture with air in any proportion,either of conditions (A) or (B) above apply. According to otherparticular embodiments, the inert gas(es) may be present in an amountsuch that the concentration(s) of H₂, CO, hydrocarbons, combustiblegases, and/or a combined concentration of H₂, CO, and hydrocarbons, inthe ranges described above, are obtained in the CO₂ product.

It can be appreciated from the above description that, in cases in whichthe CO₂ product is obtained completely from vapors generated fromhydropyrolysis, the inertization functions required for the processrepresent no (0%) contribution to the lifecycle greenhouse gas emission(GHG) value of the higher value liquid products, such as gasolineboiling-range and/or diesel fuel boiling-range hydrocarbon-containingfractions, obtained from the process. However, to the extent that theutilities and other costs required for separating CO₂ products fromtheir parent streams are considered, the inertization functions mayrepresent a minor contribution, e.g., less than about 3%, to the to thelifecycle greenhouse gas emission (GHG) value of the higher value liquidproducts. For purposes of this disclosure, the lifecycle greenhouse gasemission value may be measured based on CO₂ equivalents (e.g., grams (g)of CO₂-equivalents/megajoule (MJ) of energy or pounds (lb) of CO₂equivalents/million BTU (mmBTU of energy, wherein 1 g CO₂-eq./MJ isabout 2.33 lb CO₂-eq./mmBTU), as measured according to guidelines setforth by the Intergovernmental Panel on Climate Change (IPCC) and theU.S. federal government. Lifecycle assessment (LCA) values of emissionsin terms of CO₂ equivalents, from raw material cultivation (in the caseof plant materials) or raw material extraction (in the case of fossilfuels) through fuel combustion, can be calculated using SimaPro 7.1software and IPCC GWP 100a methodologies. In addition, although suitableCO₂ products for the inertization functions described herein may furtherinclude an inert gas such as nitrogen, or a mixture of inert gases,which is not generated from hydropyrolysis, in general the use of suchinert gas(es) does not contribute significantly to the lifecyclegreenhouse gas emission value. In other representative embodiments, theinertization functions required for the process represent a less than1%, and often a less than 0.1%, contribution to the lifecycle greenhousegas emission value of the higher value liquid products obtained from theprocess.

Description of Inertization Functions of the CO₂ Products

As described above, CO₂ products may be separated from various vaporstreams generated from hydropyrolysis and used advantageously to fulfillsome or all of the inertization requirements of the process. As will beappreciated from the discussion below, the use of CO₂ products asdescribed above for inertization functions may involve relativelystagnant (i.e., non-flowing) CO₂ product applications, such as incertain cases of inert blanketing of solids transport equipment or theblanketing of liquid containers, either under pressure or at atmosphericpressure. Alternatively, the use of such CO₂ products may involveflowing CO₂ product applications, such as in certain cases of theoperation of solids transport equipment (e.g., providing a flowing CO₂product to remove solid particles from stagnant or quiescent areas wherethey may tend to accumulate), or in conveying and/or separating solidsusing a flowing gas stream. As will also be appreciated, the use of aCO₂ product for a given inertization function may involve theintroduction of that CO₂ product into the hydropyrolysis process (e.g.,into the hydropyrolysis reactor vessel, a pre-reactor vessel, or ahydroconversion reactor vessel), such as in certain cases of inertblanketing of solids transport equipment, and particularly in cases inwhich particulate solids (and consequently their surroundingenvironment) are introduced into the hydropyrolysis process, or areotherwise transferred from one vessel of the hydropyrolysis process toanother vessel. In other cases, the use of a CO₂ product will notintroduce that CO₂ product into the hydropyrolysis reactor vessel, apre-reactor vessel, or a hydroconversion reactor vessel, as discussedabove; but rather, for example may involve the inert blanketing ofhigher value liquid products, such as gasoline boiling-range and/ordiesel fuel boiling-range hydrocarbon-containing fractions, which mayrepresent final liquid products of the process.

According to representative embodiments, at least one inertizationfunction, for example all inertization functions, will introduce CO₂product into the hydropyrolysis process. According to other embodiments,at least one inertization function, for example all inertizationfunctions, will not introduce CO₂ product into the hydropyrolysisprocess as discussed above. In still further embodiments, at least oneinertization function will introduce CO₂ product into the hydropyrolysisprocess, and at least one inertization function will not introduce CO₂into the hydropyrolysis process as discussed above

(i) Operation of Solids Transport Equipment

Solids transport equipment such as lock hoppers and solids transferscrews may be used for the safe isolation and/or handling (movement) ofparticulate solids, including the biomass-containing feedstock orbiomass-derived feedstock, as well as catalyst or other solid bedmaterial. Isolation and handling may be involved in both theintroduction of such particulate solids into, and the removal of suchparticulate solids from, representative hydropyrolysis processes asdescribed above, including, more specifically, the hydropyrolysisreactor vessel as well as the optional pre-reactor vessel, optionalhydroconversion reactor vessel(s), optional regeneration vessel, and/oroptional hydrogasification vessel. Isolation and handling may also beinvolved in the transfer of such particulate solids from one part (e.g.,vessel) of the hydropyrolysis process to another part (e.g., vessel). Inrepresentative embodiments, a CO₂ product as described above, such as aCO₂-enriched product of separation from a steam reformer effluent, maybe used for the inertization of solids transport equipment used for theintroduction, removal, or transfer of particulate solids.

In the case of solids transport equipment (e.g., lock hopper) operation,a CO₂ product, as described above, may be used for purging of theenvironment, within such equipment (e.g., lock hopper) surrounding thebiomass-containing feedstock, biomass-derived feedstock, or catalyst orother solid bed material, to be transferred, for example by displacingair from this environment. Alternatively, or in combination, a CO₂product may be used for pressurization of the environment, within suchequipment (e.g., lock hopper) surrounding the biomass-containingfeedstock, biomass-derived feedstock, or catalyst or other solid bedmaterial, to a pressure above that, in the hydropyrolysis process, atwhich the particulate solids are introduced, for example above therepresentative pressures of the hydropyrolysis reactor vessel, or abovethe representative pressures of the optional pre-reactor vessel,optional hydroconversion reactor vessel(s), optional regenerationvessel, and/or optional hydrogasification vessel, as described above.

Representative inertization functions therefore include the use of anyof the CO₂ products described herein in the operation of solidstransport equipment, and more particularly in the isolation or handlingof particulate solids. Such CO₂ products may be used for purging and/orpressurization of solids transport equipment for the introduction,removal or transfer of particulate solids, and specifically for purgingand/or pressurization of the environment within such equipment,surrounding the particulate solids. For example, solids transportequipment (e.g., lock hopper) operation for the introduction ofbiomass-containing feedstock, biomass-derived feedstock, or catalyst orother solid bed material, into the hydropyrolysis process may requirepurging of the surrounding environment, within such equipment,optionally preceding the pressurization of this environment. Solidstransport equipment (e.g., lock hopper) operation for the removal ofchar, or catalyst or other solid bed material, from the hydropyrolysisprocess may require purging of the surrounding environment, within suchequipment, optionally following the depressurization of thisenvironment. Solids transport equipment (e.g., lock hopper) operationfor the transfer of biomass-containing feedstock, biomass-derivedfeedstock, or catalyst or other solid bed material, from one part (e.g.,vessel) of hydropyrolysis process to another part (e.g., vessel) mayrequire purging of the surrounding environment, within such equipment,optionally following the depressurization of this environment, and/oroptionally preceding pressurization of this equipment.

According to some embodiments, a CO₂ product as described herein may beused for purging of solids transport equipment (e.g., the environmentwithin such equipment, surrounding the particulate solids) in any ofthese particulate solids introduction, removal, or transfer operations,whereas a different gas may be used for pressurization, for examplepreceding or following the purging. Gases used for pressurization mayinclude those that are flammable (e.g., pure hydrogen,hydrogen-containing gases, or CO-containing gases) or may include othertypes of inert gases (e.g., nitrogen) that are not CO₂ products, or donot contain CO₂ products, as described herein. Flammable gases refer tothose that are combustible or, when mixed with air in at least onemixing ratio, form a combustible mixture. According to a specificembodiment, a CO₂ product may be used for purging solids transportequipment for the introduction of particulate solids (e.g.,biomass-containing feedstock or biomass-derived feedstock) into thehydropyrolysis process, prior to pressurization of the solids transportequipment with a flammable gas (e.g., pure hydrogen or ahydrogen-containing gas), which is then used to introduce theparticulate solids into the hydropyrolysis process. Purging of solidstransport equipment (e.g., a lock hopper) is often performed atatmospheric pressure or slightly above atmospheric pressure (e.g., at apressure of less than about 3 barg), whereas pressurization may involveachieving pressures at or above the operating pressures of variousprocess equipment associated with the hydropyrolysis process (e.g., thehydropyrolysis reactor), as described herein. For example, a lock hoppermay be pressurized to a pressure of generally greater than about 30barg, and often greater than about 45 barg.

Representative operations of solids transport equipment (e.g., lockhoppers) include the introduction of:

particles of biomass-containing feedstock or biomass-derived feedstockto the hydropyrolysis reactor vessel, for example, through ahydropyrolysis reactor feedstock inlet configured to introduce suchfeedstock to within or to below a fluidized bed comprising deoxygenatingcatalyst;particles of deoxygenating catalyst to the hydropyrolysis reactor vessel(e.g., at a rate suitable to compensate for losses, such as attritionlosses, plus any net removal rate from the hydropyrolysis reactorvessel), for example through the hydropyrolysis reactor feedstock inletdescribed above, or alternatively through a separate deoxygenatingcatalyst inlet configured to introduce deoxygenating catalyst to withinor to below a fluidized bed comprising deoxygenating catalyst;particles of biomass-containing feedstock or biomass-derived feedstockto a pre-reactor vessel, for example, through a pre-reactor feedstockinlet configured to introduce such feedstock to within or to below afluidized particle bed comprising such feedstock and optionally a solidbed material; and/orparticles of solid bed material to a pre-reactor vessel (e.g., at a ratesuitable to compensate for losses, such as attrition losses, plus anynet removal rate from the pre-reactor vessel), for example, through thepre-reactor feedstock inlet described above, or alternatively through aseparate bed material inlet configured to introduce biomass-containingfeedstock or biomass-derived feedstock to within or to below a fluidizedparticle bed comprising such feedstock and the solid bed material;

Representative operations of solids transport equipment (e.g., lockhoppers) include the removal of:

particles of char, for example from the output of a filtration orcentrifugation device (e.g., a cyclone) that is configured to separateor enrich char received from a pre-reactor vapor stream or ahydropyrolysis reactor output;

particles of deoxygenating catalyst (e.g., in a spent or deactivatedcondition, due to coking or the accumulation of other deposits) and/orchar from the hydropyrolysis reactor vessel, for example through adeoxygenating catalyst drawoff outlet configured to remove deoxygenatingcatalyst and/or char from within a fluidized bed comprisingdeoxygenating catalyst;particles of biomass-derived feedstock or biomass-containing feedstock(e.g., enriched in one or more inert materials, such as glass, metal, orplastic, relative to the biomass-containing feedstock introduced to thehydropyrolysis process), particles of solid bed material (e.g., in aspent or deactivated condition, due to coking or the accumulation ofother deposits), and/or particles of char, from a pre-reactor vessel,for example through a solids drawoff outlet configured to remove suchfeedstock, solid bed material, and/or char from within a fluidized bedcomprising one or both of these types of solid particles;particles of regenerated solid bed material and/or regenerated catalyst(e.g., following the combustion of coke or other accumulated deposits)from a regeneration vessel, for example through a regenerator drawoffoutlet configured to remove the regenerated solid bed material and/orregenerated catalyst from within a fluidized bed (e.g., a centralsection thereof) comprising one or both of these types of solidmaterials; and/orparticles of hydrogasified solid bed material and/or hydrogasifiedcatalyst (e.g., following the hydrogasification of coke or otheraccumulated deposits) from a hydrogasification vessel, for examplethrough a hydrogasifier drawoff outlet configured to remove thehydrogasified solid bed material and/or hydrogasified catalyst fromwithin a fluidized bed (e.g., a central section thereof) comprising oneor both of these types of solid materials.

Representative operations of solids transport equipment (e.g., lockhoppers) include the transfer of:

particles of deoxygenating catalyst (e.g., in a partially spent orpartially deactivated condition, due to coking or the accumulation ofother deposits, and optionally in combination with, or having beenseparated from, particles of char) from the hydropyrolysis reactorvessel, for example from the deoxygenating catalyst drawoff outlet, asdescribed above, to a pre-reactor vessel, for example, to thepre-reactor feedstock inlet described above, or alternatively through aseparate bed material inlet as described above;particles of deoxygenating catalyst (e.g., in a spent or deactivatedcondition, due to coking or the accumulation of other deposits, andoptionally in combination with, or having been separated from, particlesof char) from the hydropyrolysis reactor vessel, for example from thedeoxygenating catalyst drawoff outlet, as described above, to aregeneration vessel or a hydrogasifier vessel, for example through aregenerator inlet or a hydrogasifier inlet, respectively, configured tointroduce particles of deoxygenating catalyst to within or to below afluidized bed comprising deoxygenating catalyst;particles of solid bed material (e.g., in a partially spent or partiallydeactivated condition, due to coking or the accumulation of otherdeposits, and optionally in combination with, or having been separatedfrom, particles of char) from a pre-reactor vessel, for example throughthe solids drawoff outlet as described above, and optionally following aseparation to enrich the concentration of solid bed material relative tothat of biomass-containing feedstock or biomass-derived feedstock, tothe hydropyrolysis reactor vessel, for example, to the hydropyrolysisreactor feedstock inlet described above, or alternatively through aseparate deoxygenating catalyst inlet described above;particles of solid bed material (e.g., in a spent or deactivatedcondition, due to coking or the accumulation of other deposits, andoptionally in combination with, or having been separated from, particlesof char) from a pre-reactor vessel, for example through the solidsdrawoff outlet as described above, and optionally following a separationto enrich the concentration of solid bed material relative to that ofbiomass-containing feedstock or biomass-derived feedstock, to aregeneration vessel or a hydrogasifier vessel, for example through aregenerator inlet or a hydrogasifier inlet, respectively, configured tointroduce particles of solid bed material to within or to below afluidized bed comprising deoxygenating catalyst;particles of biomass-derived feedstock or biomass-containing feedstock(e.g., depleted in one or more inert materials, such as glass, metal, orplastic, relative to the biomass-containing feedstock introduced to thehydropyrolysis process, and optionally in combination with, or havingbeen separated from, particles of char) from a pre-reactor vessel, forexample through a solids drawoff outlet as described above, andoptionally following a separation to enrich the concentration of suchfeedstock relative to that of solid bed material, to the hydropyrolysisreactor vessel, for example to the hydropyrolysis reactor feedstockinlet described above, or alternatively through a separate deoxygenatingcatalyst inlet described above;particles of regenerated solid bed material and/or regenerated catalyst,as described above, from a regeneration vessel, for example through aregenerator drawoff outlet as described above, to the hydropyrolysisreactor vessel, for example to the hydropyrolysis reactor feedstockinlet described above, or alternatively through a separate deoxygenatingcatalyst inlet described above;particles of hydrogasified solid bed material and/or hydrogasifiedcatalyst, as described above, from a hydrogasification vessel, forexample through a hydrogasifier drawoff outlet as described above, tothe hydropyrolysis reactor vessel, for example to the hydropyrolysisreactor feedstock inlet described above, or alternatively through aseparate deoxygenating catalyst inlet described above;particles of regenerated solid bed material and/or regenerated catalyst,as described above, from a regeneration vessel, for example through aregenerator drawoff outlet as described above, to a pre-reactor vessel,for example, to the pre-reactor feedstock inlet described above, oralternatively through a separate bed material inlet as described above;and/orparticles of hydrogasified solid bed material and/or hydrogasifiedcatalyst, as described above, from a hydrogasification vessel, forexample through a hydrogasifier drawoff outlet as described above, to apre-reactor vessel, for example, to the pre-reactor feedstock inletdescribed above, or alternatively through a separate bed material inletas described above.

In addition to, or as an alternative to, the use of lock hoppers for anyof the above operations for the introduction, removal, and/or transferof solids, other solids transport devices may be used, includingscrew-type conveyers (e.g., augers and screw extruders). The CO₂products described herein can be used for the inertization of suchequipment and devices (e.g., to reduce the possibility of fire orexplosion due to static electricity resulting from the solidstransport). Otherwise, CO₂ products described herein may aid in thefunctioning of such solids transport equipment, by providing a flowingCO₂ product that directly contacts and forces solid particles in thedesired direction and/or away from stagnant or quiescent areas wheresuch solids might otherwise tend to accumulate, settle, and/oragglomerate.

Furthermore, in addition to the isolation and handling (movement) ofparticulate solids, inertization functions associated with the operationof solids transport equipment extend to temperature control and/or theisolation of the solids transport equipment itself. According to someembodiments in which the inertization function additionally comprisestemperature control, this function may more specifically compriseflowing a CO₂ product, as described herein, through at least a portionof the solids transport equipment, for example a solids transfer screw,to raise or lower the temperature of the solids transport equipmentand/or particulate solids being transferred, for example, according tothe operations described above. For temperature control or thermalmanagement of the solids transport equipment and/or particulate solids,a CO₂ product as described herein may perform a cooling function, forexample by limiting the temperature of particulate solids passingthrough a solids transfer screw and/or improving the dissipation of heatgenerated from its operation. A flowing CO₂ product may also providelocalized temperature control within the hydropyrolysis process, forexample at a point of introduction, using solids transport equipment(e.g., a solids transfer screw), of particulate solids such asbiomass-containing feedstock or biomass-derived feedstock into afluidized bed. Alternatively, a flowing CO₂ product may perform aheating function, for example to maintain the solids transport equipment(e.g., a solids transfer screw) at above ambient temperature, in orderto prevent condensation and/or freezing of water on and around theequipment. According to other embodiments, in which the inertizationfunction comprises isolation of the transport equipment itself, a CO₂product as described herein may perform a “padding” operation. Thisinvolves the pressurization of the CO₂ product between two adjacentvalves in series, with these valves, between which the CO₂ product isisolated, being either bolted directly onto one another, or otherwiseseparated by a piping section (e.g., a short spool piece) or a smallvessel or chamber. The pressure in the space between the valves, inwhich the CO₂ product is isolated (e.g., in a non-flowing or stagnantcondition), normally exceeds the pressure (e.g., by a safety margin ofat least about 3 bar) of the gas composition on one, but preferablyboth, of the opposite sides of the valves, which are in fluidcommunication with these compositions. These opposite, or opposing,sides namely refer to those sides of the valves that are not in fluidcommunication with the CO₂ product when the valves are closed.Therefore, if a first gas composition (e.g., a high pressure,hydrogen-containing gas) is on one opposing side of the valve pair, asecond gas composition (e.g., ambient pressure air) is on anotheropposing side of the valve pair, and the pressurized CO₂ product isisolated between the valves of the valve pair, the first gas compositioncannot leak through both valves, in the event of internal valve failure,and thereby mix with the second composition. Rather, the pressurized CO₂product will leak through to the first and/or the second gascompositions, in the direction toward the opposing sides of valve pair.In this manner, the CO₂ product can be used for an inertizationfunction, and specifically an isolation function, whereby the CO₂product is isolated between gas compositions that, if mixed, could, inat least one mixing ratio, result in a flammable gas mixture.

(ii) Blanketing of Liquid Containers

CO₂ products, as described above, may additionally, or alternatively, beutilized for the inert gas blanketing of vessels for containingintermediate and/or final liquid products, condensed from vapors ofhydropyrolysis processes as described above. An example of such a liquidproduct is a hydropyrolysis bio-oil that is condensed from thehydropyrolysis reactor vapor as described above, wherein thehydropyrolysis reactor vapor is preferably obtained from ahydropyrolysis reactor output, following the removal of solid charparticles from this output. This condensed hydropyrolysis bio-oil mayrepresent an end product and be used, for example, as a liquid fuelblending component. In the case of a hydropyrolysis process comprising afurther hydroconversion step, as described above, this hydropyrolysisbio-oil may alternatively represent an intermediate liquid product,which may be further treated or reacted (e.g., for furtherdeoxygenation), by hydroconversion. If a downstream hydroconversion stepis used, the higher value liquid products obtained from this step, suchas gasoline boiling-range and/or diesel fuel boiling-rangehydrocarbon-containing fractions, may represent final liquid products ofthe process.

Any of the CO₂ products described above may be used for the blanketingof vessels for containing such intermediate or final liquid products.For example, a suitable CO₂ product may be used to purge the headspaceabove one or more of such vessels and maintain this headspace filledwith a CO₂ product in a sealed condition, to prevent ambient air fromentering this headspace. Often, atmospheric pressure or a positivepressure (e.g., less than about 3 barg) can be maintained by allowingthe CO₂ product to enter the vessel and replace, on pressure demand,liquid product that is withdrawn from the vessel. In some cases,blanketing of vessels may be achieved with a slight purge or flow of CO₂product entering and exiting the vessel, either at atmospheric pressureor at a positive pressure as described above. Whether blanketing isperformed using the CO₂ product in a stagnant or flowing condition, ifpositive pressure is maintained, it should be sufficient forpressurizing the suction side of liquid transport equipment (e.g.,pumps) used to convey the intermediate or final liquid products to otherparts (e.g., vessels) of the hydropyrolysis process or otherwise, forexample, to storage containers.

(iii) Drying of the Biomass-Containing Feedstock or Biomass-DerivedFeedstock

The biomass-containing feedstock or biomass-derived feedstock may beused in a dry form, for example, after being subjected to a drying stepsufficient to reduce the moisture content of the initial feedstock toless than about 1% by weight, or even less than about 0.1% by weight).According to other embodiments, the initial feedstocks may includemoisture (e.g., have a moisture content of greater than about 1%, suchas from about 1% to about 10% by weight). In still other embodiments,the initial feedstock may be used in the form of an aqueous slurry. Ingeneral, processes described herein do not require a severely driedinitial feedstock, as the inclusion of water can be beneficial in termsof its ability to form hydrogen via the water-gas shift reaction underconditions in one or more of a pre-reactor vessel, the hydropyrolysisreactor vessel, and/or a hydroconversion reactor vessel, as describedabove.

Any of the above CO₂ products, for example a CO₂-enriched product ofseparation from a steam reformer effluent, as described above, may beused as a source of flowing gas for drying of the biomass-containingfeedstock and/or biomass-derived feedstock at ambient, but preferablyelevated, temperature. In a representative embodiment, the CO₂ productand/or such feedstock are heated to an elevated temperature (e.g.,greater than about 30° C., and preferably greater than about 50° C.),and the CO₂ product is passed through such feedstock for a timesufficient to reduce its moisture content to a desired value. Continuousdrying of such feedstock may be achieved by flowing the CO₂ productthrough a flowing stream (e.g., in a countercurrent manner) of suchfeedstock, for example at a flow rate equal or substantially equal tothat of its introduction to the hydropyrolysis reactor or a pre-reactoras described above. For drying applications, the CO₂ product shouldpreferably have a low moisture content, for example a concentration ofgaseous H₂O of less than about 5% by volume, and preferably less thanabout 1% by volume. The extent of drying of such feedstock may bemonitored or controlled by measuring the moisture level of flowing gasexiting a drying stage. An online moisture analyzer may be appropriatefor this purpose.

(iv) Conveying and/or Separating Solids Using a Flowing Gas Stream

CO₂ products as described above, for example a CO₂-enriched product ofseparation from a steam reformer effluent, may be provided as inertflowing gas streams that are used for conveying solids. These CO₂products may accompany, or be used exclusively in place of, solidstransport equipment as discussed above. For example, the use of a CO₂product for conveying solids may accompany lock hopper operation byblowing solid particles away from stagnant or quiescent areas where suchsolids might otherwise tend to accumulate, settle, and/or agglomerate.

Representative operations in which CO₂ products may be used forconveying solids include those specific operations as described abovewith respect to the use of solids transport equipment (e.g., lockhoppers) for the introduction, removal, or transfer of particulatesolids. Generally, if a flowing CO₂ product is used for conveyingparticulate solids, a superficial gas velocity is used that issufficient to entrain (i.e., exceeds the terminal velocity of) most orsubstantially all of the solid particles being conveyed. The gasvelocities used for conveying particulate solids, in the direction ofthe desired flow of the solid particles, will generally exceed thoseused for other inertization functions as described herein, which alsoinvolve the use of a flowing CO₂ product. Such inertization functionsinclude, for example, those additionally comprising temperature control,such as in the case of cooling a solids transfer screw as discussedabove. In such cases, the superficial gas velocity of the CO₂ productbeing used will generally be below the terminal velocity of a solidparticle having an average diameter and density of the solid particlesbeing conveyed. In many cases, the superficial gas velocity will bebelow the terminal velocity of all or substantially all of the solidparticles.

In addition, these CO₂ products, when provided as inert flowing gasstreams, may be used for separating solids (e.g., by classificationaccording to their fluid dynamic properties (e.g., terminal velocity).For example, as described above with respect to the use of solidstransport equipment, (i) particles of biomass-derived feedstock orbiomass-containing feedstock (e.g., depleted in one or more inertmaterials) may be transferred from a pre-reactor vessel, to thehydropyrolysis reactor vessel, following a separation to enrich theconcentration of biomass-containing feedstock or biomass-derivedfeedstock relative to that of solid bed material; (ii) particles ofsolid bed material (e.g., in a partially spent or partially deactivatedcondition) may be transferred from a pre-reactor vessel to thehydropyrolysis reactor vessel, following a separation to enrich theconcentration of solid bed material relative to that ofbiomass-containing feedstock or biomass-derived feedstock; and (iii)particles of solid bed material (e.g., in a spent or deactivatedcondition) may be transferred from a pre-reactor vessel, to aregeneration vessel or a hydrogasifier vessel, following a separation toenrich the concentration of solid bed material relative to that ofbiomass-containing feedstock or biomass-derived feedstock. Theseseparations, to enrich one type of solid particle with respect toanother, may be performed using any of the CO₂ products, as describedabove, as a flowing inert gas for performing a solids separation orclassification operation. In a representative embodiment, a flowing gasstream of a CO₂ product as described above may be used to sort solidparticles in a pneumatic separator, to provide fractions of differingdensities or other differing fluid dynamic property (e.g., terminalvelocity).

REPRESENTATIVE EMBODIMENTS

In an aspect of the disclosure, a process is provided wherein carbondioxide (CO₂) is separated from the product vapors generated byintegrated hydropyrolysis and hydroconversion, and the separated carbondioxide is then used as an inert gas in order to sustain at least oneother step of the process. The vapor stream emerging from an integratedhydropyrolysis and hydroconversion plant, downstream of a liquid productrecovery stage, will contain substantial amounts of carbon monoxide,carbon dioxide, and hydrocarbon vapors (e.g., methane, ethane, propane,butane, isobutane, pentane, pentene, etc.). In an aspect of thedisclosure, the vapor stream may be sent to a steam reformer, and agaseous reformer effluent stream, comprising hydrogen and carbon dioxide(e.g., in a combined amount generally exceeding 50% by volume), may beobtained.

The gaseous stream comprising primarily hydrogen and carbon dioxide maybe separated into a first stream comprising hydrogen and a second streamcomprising carbon dioxide, wherein the first stream and the secondstream are distinct from each other. In an aspect of the disclosure, asuitable separation apparatus is used to separate hydrogen and carbondioxide. A suitable separation apparatus may comprise an amine scrubberto separate the carbon dioxide stream from the hydrogen stream. Inaccordance with aspects of the disclosure, the process comprises usingthe separated carbon dioxide as an inert gas in order to sustain atleast one other step of the process. In an aspect, the at least oneother step of the process is selected from the group consisting ofoperating a lock hopper, blanketing of flammable fluids, dryingfeedstock, pressurizing a vessel, and conveying a fluid by using theseparated carbon dioxide as a carrier gas. Surprisingly, it has beenfound that the amount of available separated carbon dioxide that isobtained in accordance with aspects of the disclosure equals or exceedsthe amount of inert gas needed to sustain industrial operations of ahydropyrolysis process, including the hydropyrolysis process disclosedin U.S. Pat. No. 8,492,600, which is incorporated herein by reference inits entirety.

In an aspect, a hydropyrolysis process is configured to convert solidfeedstocks to useful fuels. Solid feedstocks may be preferably handledin lock hopper systems. A lock hopper may be configured to remove airfrom the solid feedstock, and is then used to bring the feedstock up tothe operating pressure of the hydropyrolysis process. An inert gas maybe used to carry out either or both of these tasks, as described above,and the inert gas can be provided in the form of CO₂ recovered from theeffluent stream of the steam reformer. An inert gas may also be neededto blanket liquid hydrocarbon product storage tanks, so that explosionsand fires in these tanks can be avoided. A heated stream of inert gasmay be also needed to dry feedstock without risking ignition and fire.

In an aspect, a vapor stream is generated from an integratedhydropyrolysis and hydroconversion process downstream of a liquidproduct recovery stage, wherein the vapor stream comprises substantialamounts of carbon monoxide, along with non-condensable hydrocarbonvapors (methane, ethane, etc.). These vapors are sent to a steamreformer, and a gaseous stream, comprising hydrogen and carbon dioxideis obtained. This gaseous stream is then separated into distinctstreams, wherein a first stream comprises hydrogen, and a second streamcomprises carbon dioxide. In accordance with aspects of the disclosure,the process comprises conveying the second stream to locations withinthe hydropyrolysis plant where an inert gas is required or is found tobe useful.

In an aspect, an integrated hydropyrolysis and hydroconversion processis provided. The process may be operated at a maximum pressure of 558.6psig (38 barg), and may convert at least about 1000 metric tons/day ofwood, on a dry, ash-free basis to useful fuels. Steps of the process maycomprise loading of feedstock and makeup catalyst into lock hoppers,transferring of feedstock and makeup catalyst from the lock hoppers tothe first-stage (hydropyrolysis) reactor, separating and recovering charand elutriated catalyst from the process vapor stream, hydroconvertingof the process vapors in a second-stage reactor, condensing andrecovering aqueous and liquid hydrocarbon products, converting processvapor components in a steam reformer, and separating CO₂ from themixture of hydrogen and CO₂ leaving the reformer.

Based on engineering simulations associated with this process design,the following figures have been obtained.

CO₂ Supply:

Source Avg Kg/hr Amine system 13,585 High Pressure Recycle Drum 4,999Low Pressure Recycle Drum 3,454 Total hourly CO₂ supply 22,038

The values given are hourly averages, since the most intensiveapplication of inert gas is associated with intermittent lock hopperoperation. Lock hoppers may be used to introduce solid feedstock andmakeup catalyst into the process, and to remove solid char product fromthe process. The high-pressure recycle drum (mentioned above) may beconfigured to receive inert gas from a lock hopper at high pressure,which allows the lock hopper pressure to be lowered to a point whereinert gas can be transferred to the low pressure recycle drum (mentionedabove). The low pressure recycle drum may be configured to receive inertgas until the lock hopper pressure has fallen so far that directde-pressurization to atmosphere is called for, since the pressure in thelow-pressure drum is, at that point, nearly equal to the pressure of thelock hopper. During re-pressurization of a lock hopper, the lock hoppermay be initially pressurized with recycled inert gas from thelow-pressure recycle drum, and is subsequently raised to a significantlyhigher pressure by the transfer of recycled inert gas from thehigh-pressure recycle drum. Both the high and low-pressure recycle drumsmay reduce the net need for inert gas associated with operation of theplant, and may be handled as sources of inert CO₂ in this simulation.

CO₂ Consumption:

Destination Avg Kg/hr Catalyst (pressurization and transport) 241Re-Pressure Char Drum 2588 Re-Pressure Lockhoppers 9384 Maintainpressure on feed drum 3542 during material draw down Feedstock TransferScrew Blanketing 50 Total hourly CO₂ consumption 15,805Devolatilization and/or Partial Hydropyrolysis in a Pre-Reactor

Particular aspects of the disclosure relate to processes for producingliquid products from biomass-containing feedstocks. Representativeprocesses comprise contacting the feedstock with carbon dioxide and/orhydrogen in a pre-reactor vessel containing a solid bed material, todevolatilize and/or at least partially hydropyrolyze the feedstock(i.e., at least partly pyrolyze or thermally decompose the feedstock inthe presence of the hydrogen). Accordingly, the processes may comprisedevolatilizing the feedstock in a pre-reactor vessel containing carbondioxide and/or hydrogen and a solid bed material, in which thedevolatilization may, but does not necessarily, accompanyhydropyrolysis. Those skilled in the art, consulting the presentdisclosure, will appreciate the operating parameters needed to achievedevolatilization or a combination of devolatilization and hydropyrolysisin the pre-reactor. Unless noted otherwise, the term “devolatilizing” ismeant to encompass both devolatilization only, in addition to acombination of devolatilization and hydropyrolysis. In particularembodiments, the devolatilization is performed without accompanyinghydropyrolysis.

The devolatilizing step of representative processes may includeintroducing a pre-reactor gas and the feedstock to the pre-reactorvessel containing the solid bed material. The pre-reactor gas andfeedstock may be introduced as separate streams to the pre-reactor orotherwise mixed prior to their introduction. The pre-reactor gas and/orfeedstock, whether or not mixed prior to being introduced to thepre-reactor, may be divided and directed to multiple (i.e., at leasttwo, for example from two to ten) inlet locations, which may, forexample, correspond to different axial heights of the pre-reactorvessel. Some portion, or all, of these heights may be below the heightof a bed (e.g., a fluidized particle bed) of solid bed material withinthe reactor. Likewise, another portion, or all, of these heights may beabove the height of such a bed. The pre-reactor gas may comprise carbondioxide and/or hydrogen. When the pre-reactor gas comprises hydrogen,the pre-reactor vessel will contain hydrogen and hydropyrolysis mayaccompany the devolatilization, as described above. In addition tocarbon dioxide, it is also possible, according to other embodiments, touse other non-hydrogen containing pre-reactor gases containing, forexample, nitrogen, oxygen, helium, etc. and mixtures of these incombination with carbon dioxide. In accordance with aspects of thedisclosure, the amount of carbon dioxide generated downstream ofhydropyrolysis and hydroconversion is sufficient to serve as thepre-reactor gas for devolatilization of the feedstock in thepre-reactor. In the case of a non-hydrogen containing pre-reactor gas,pyrolysis (rather than hydropyrolysis) may accompany devolatilization ofthe feedstock in the pre-reactor.

Whether or not the pre-reactor gas contains hydrogen, in someembodiments this gas may be used to fluidize the solid bed material,such that it may be more descriptively termed a “pre-reactor fluidizinggas.” Accordingly, the solid bed material, optionally together withchar, in the pre-reactor may be present as a fluidized bed, and inparticular as a particulate fluidization, bubbling, slugging, turbulent,or fast fluidized bed, depending on the superficial gas velocity of thepre-reactor fluidizing gas. In such fluidized bed systems, thepre-reactor may advantageously include an expanded solids disengagementsection (i.e., a section of expanded reactor diameter or cross-sectionalarea, relative to the diameter or cross-sectional area of the fluidizedbed) at a suitable height above the fluidized bed (e.g., above thetransport disengaging height, TDH), in order to promote the separationof solid particles. Other gas-solids separation devices (e.g., filters,cyclones, etc.) may be employed in place of, but preferably incombination with, the use of an expanded solids disengagement section. Acirculating fluidized bed system for the pre-reactor may also beemployed.

Overall, according to some embodiments, the step of devolatilizing thefeedstock in the pre-reactor vessel may be performed using a fluidizedbed of the feedstock and the solid bed material, together with charparticles generated via devolatilization of the feedstock, in thepre-reactor vessel. Fluidization in the pre-reactor vessel may beperformed with a pre-reactor fluidization gas having a superficialvelocity effective for carrying out the type of fluidization desired(e.g., bubbling bed fluidization), considering the properties of thebiomass-containing feedstock, conditions within the pre-reactor vessel,and the particular fluidization gas being used. In general, apre-reactor fluidization gas, and particularly a fluidization gascomprising carbon dioxide and/or hydrogen, will have a superficialvelocity of generally greater than about 3 meters per second (m/s)(e.g., from about 3 m/s to about 25 m/s), typically greater than about 5m/s (e.g., from about 5 m/s to about 15 m/s), and often greater thanabout 7 m/s (e.g., from about 7 m/s to about 12 m/s).

In other embodiments, the pre-reactor may contain a solid bed material,as described herein that is not fluidized. For example, a heated ballmill may be used to devolatilize the feedstock (e.g., in the presence ofpure carbon dioxide, a carbon dioxide-containing gas, pure hydrogen, ahydrogen-containing gas, or other gas used to achieve devolatilization)at ambient or elevated pressure. Devolatilization may be conducted, forexample, in the presence of carbon dioxide and/or hydrogen at elevatedpressure.

The solid bed material may be selected from a pretreating catalyst, asorbent, a heat transfer medium, and mixtures thereof. Suitable solidbed materials include those having dual or multiple functions. Forexample, a “pretreating catalyst” may also act to transfer heat to orfrom the pre-reactor and specifically to the particles of initialfeedstock that contain biomass. Likewise, a “heat transfer medium” maybe inert in the environment of the pre-reactor, but it may also havecatalytic and/or adsorptive capacity with respect to any reactants orother components in the environment of the pre-reactor. Unless notedotherwise, the designations “pretreating catalyst,” “sorbent,” or “heattransfer medium,” include solid bed materials having functions otherthan purely catalytic, adsorptive, or heat transfer functions,respectively, in the environment of the pre-reactor. It is possible,however, in alternative embodiments, for a solid bed material to be apretreating catalyst but not have adsorptive capacity for components inthe environment of the pre-reactor and/or not act to transfer heat to orfrom the pre-reactor. Likewise, it is possible for a solid bed materialto be a sorbent but not have catalytic activity with respect toreactants or other components in the environment of the pre-reactorand/or not act to transfer heat to or from the pre-reactor. Similarly,it is possible for a solid bed material to be a heat transfer medium butnot have catalytic activity with respect to reactants or othercomponents in the environment of the pre-reactor and/or not haveadsorption capacity for components in the environment of thepre-reactor. Mixtures of different solid bed materials that arepretreating catalysts, sorbents, and/or heat transfer media as definedabove (e.g., a mixture of a catalyst and a heat transfer medium) mayalso be used.

According to a particular embodiment, the solid bed material may be aheat transfer medium, with or without adsorption capacity, such that thebed material promotes devolatilization of the feedstock and eitheradsorbs catalyst poisons and/or corrosive species (e.g., chloride) orallows such poisons and/or corrosive species to be removed with charexiting the pre-reactor. In the latter case, in which the solid bedmaterial promotes devolatilization but lacks adsorption capacity, thepoisons and/or corrosive species may nevertheless be separated from thepre-reactor vapor stream exiting the pre-reactor. Using such aseparation step, the poisons and/or corrosive species may be absent orsubstantially absent from the portion of the pre-reactor vapor streamthat is passed to the hydropyrolysis reactor vessel, despite the lack ofadsorptive capacity. Overall, the particular function(s) chosen for thesolid bed material will depend on the nature of the biomass-containingfeedstock and the nature of the impurities contained therein.

According to exemplary embodiments, described in greater detail below,the solid bed material used in the pre-reactor vessel may be apretreating catalyst having activity for cracking or deoxygenation ofthe feedstock. Particular pretreating catalysts (e.g.,zeolite-containing catalysts such as ZSM-5 catalysts) may have activityfor both cracking and deoxygenation. According to other exemplaryembodiments, the solid bed material may include a sorbent having thecapacity to adsorb corrosive species (e.g., chloride-containingspecies). The solid bed material may alternatively, or in combination,include a sorbent having the capacity to adsorb poisons (e.g., metalcontaminants such as sodium) of the deoxygenating catalyst and/orhydroconversion catalyst. This can result in a pretreated feedstock,used subsequently in hydropyrolysis, having at least the improvedcharacteristic(s) of a reduced corrosive species content, a reducedhydropyrolysis catalyst poison content, and/or a reduced hydroconversioncatalyst poison content.

In representative embodiments, pretreatment in a pre-reactor, asdescribed above, produces a pre-reactor vapor stream comprisingentrained solid particles (e.g., particles of char and/or solid bedmaterial). Alternatively, depending on the operating conditions andgas-solid separations occurring within the pre-reactor, the pre-reactorvapor stream may be substantially or completely devoid of solid bedmaterial. The pre-reactor vapor stream may include condensable gases(e.g., water vapor and/or oxygenated hydrocarbons such as phenols) aswell as non-condensable gases (e.g., hydrogen, CO, and/or CO₂). Thecondensable gases will generally have a high oxygen content (e.g., inthe range from about 35% to about 55% by weight), characteristic ofconventional bio-oils obtained from pyrolysis in the substantial absenceof any deoxygenation reactions. Normally, the pre-reactor vapor stream,or at least a portion thereof, will be passed completely in the vaporphase to a subsequent hydropyrolyzing step, without intermediatecondensing of any portion of this stream. However, intermediatecondensing with re-heating may also be possible, for example, toselectively condense unwanted components of relatively low volatility(relatively high boiling point), optionally providing a liquidcondensate “wash” for removing at least some char and/or other solidparticles. In other embodiments, the pre-reactor vapor stream may bepartially condensed and passed as a mixed vapor and liquid phase to thesubsequent hydropyrolyzing step. Partial condensation may occur, forexample, when heat is recovered from the pre-reactor vapor stream (e.g.,by heat exchange with a cooler stream), or when heat is otherwise lostto the environment.

As is apparent from the above description, all or a portion of thepre-reactor vapor stream exiting the pre-reactor may be subjected to thesubsequent hydropyrolyzing step. Between the steps of devolatilizing andhydropyrolyzing, the pre-reactor vapor stream may, by separation orreaction (e.g., water-gas shift reaction), be enriched with respect toone or more desired components and/or depleted with respect to one ormore undesired components (e.g., in the case of partial condensation,which may serve to remove some of the solid particles). The pre-reactorvapor may also be mixed prior to or during the hydropyrolyzing step withone or more additional streams. Accordingly, unless otherwise noted, thestep of hydropyrolyzing at least a portion of the pre-reactor vaporstream is meant to encompass such intermediate steps as separation,reaction, and/or mixing of the pre-reactor vapor stream or portionthereof. In some embodiments, however, the pre-reactor process vaporstream or portion thereof may be subjected to the hydropyrolyzing step,without an intermediate step of being enriched with respect to one ormore desired components and/or depleted with respect to one or moreundesired components, by separation or reaction. For example a portionof the pre-reactor process vapor stream may be split from the entireeffluent of the pre-reactor, with little or no change in itscomposition. Likewise, the pre-reactor vapor stream, or portion thereof,may be subjected to the hydropyrolyzing step, without being mixed priorto or during the hydropyrolyzing step with one or more additionalstreams. However, in many cases it will be desirable to mix thepre-reactor vapor stream or portion thereof with hydrogen or ahydrogen-containing gas stream that provides additional hydrogen (beyondthat contained in the pre-reactor vapor stream or portion thereof alone)for hydropyrolysis as described below.

Thus, some or all of the pre-reactor vapor stream may be passed to ahydropyrolysis reactor vessel. In the case of a pre-reactor vapor streamthat contains entrained solid particles, it may be desirable to separatea relatively low quality portion of this vapor stream, such as asolids-enriched stream (i.e., having a higher concentration of solidsrelative to that of the pre-reactor vapor stream) and a purifiedpre-reactor vapor stream (having a lower concentration of solidsrelative to that of the pre-reactor vapor stream). In this low quality,solids-enriched stream, the solid particles may also have a higheraverage particle size and/or a higher average particle weight (e.g., inthe case of cyclone separation, electrostatic precipitation, or otherseparation based on particle size or having a particle size cutoff),compared to solid particles in the purified pre-reactor vapor stream(and also compared to the total solid particles in the pre-reactor vaporstream prior to the separation). In such an embodiment where aseparation of the pre-reactor vapor stream is performed, in order toprovide a relatively low quality, solids-enriched stream, the relativelyhigh quality, purified pre-reactor vapor stream may be the portion ofthe pre-reactor vapor stream that is hydropyrolyzed in thehydropyrolysis reactor vessel.

In the case of removal of a portion, for example substantially all, ofthe entrained solid particles from the pre-reactor vapor stream, theresulting purified pre-reactor vapor stream may represent a suitableportion of the pre-reactor output that is sent to a subsequenthydropyrolyzing step in a hydropyrolysis reactor vessel. According tosome embodiments, entrained solid particles in the pre-reactor vaporstream may comprise both a portion of the solid bed material, asdescribed above, and char formed from the initial feedstock. In thiscase, representative processes may comprise recovering at least aportion of the entrained solid bed material for re-use in thepre-reactor, optionally with supplemental heating of the recovered solidbed material, in order to transfer heat into the pre-reactor vessel.Specifically, a step of (1) separating, from the entrained solidparticles (e.g., present in the pre-reactor vapor stream), a firstfraction enriched in the char and a second fraction enriched in thesolid bed material (i.e., meaning that the fractions, which maythemselves be solid-containing gas streams, are enriched relative to thecontent of the char and solid bed material, respectively, in thepre-reactor vapor stream) may be employed. This may be accompanied bythe subsequent steps of (2) heating at least a portion of the secondfraction and (3) returning the second fraction, or portion thereof thathas been heated, back to the pre-reactor vessel.

The solid bed material may alternatively be withdrawn from thepre-reactor vessel, not as entrained particles in the pre-reactor vaporstream, but from a fluidized particle bed within this vessel. In eithercase of withdrawing the solid bed material from the pre-reactor vessel,i.e., in the pre-reactor vapor stream exiting the pre-reactor or from asolids drawoff outlet exiting the particle bed, the withdrawn solidmaterial may be separated from solid char particles in a fractionenriched in the solid bed material (e.g., by using a density separation)and returned to the pre-reactor. Prior to the return of the fractionenriched in the solid bed material, this fraction may be heated tointroduce needed heat into the pre-reactor. The heating and return ofany removed solid bed material may, according to alternativeembodiments, be beneficial in the absence of a separation that providesa fraction enriched in the solid bed material. In many cases, solid bedmaterial removed from the pre-reactor may have accumulated coke andcarbon deposited thereon, as a result of its use in the operation of thepre-reactor. Therefore, any removed solid bed material, either in thepre-reactor vapor stream or from the particle bed, and whether or notseparated into a fraction enriched in the solid bed material, may besubjected to conditions under which accumulated coke and carbon areremoved, prior to the return of the solid bed material to thepre-reactor (e.g., in a heated condition). Representative conditionsinclude oxidizing conditions sufficient to regenerate the solid bedmaterial by removing the accumulated coke and carbon by combustion, aswell as reducing conditions (e.g., in the presence of a flowinghydrogen-containing gas) sufficient to hydrogasify the accumulated cokeand carbon, converting these contaminants to methane and other lighthydrocarbons. Regeneration and hydrogasification, for example in afluidized bed that simultaneously acts to classify solid particlesremoved from the pre-reactor, are described in greater detail below. Thesimultaneous hydrogasification and sulfiding of removed solid bedmaterial is also described in greater detail below.

Representative devolatilizing steps may therefore comprise withdrawing aportion of the solid bed material from the pre-reactor vessel andcontacting this portion with a fluidizing oxygen-containing gas (in thecase of regeneration) or otherwise with a fluidizing hydrogen-containinggas (in the case of hydrogasification), to either combust coke andcarbon that has accumulated on the solid bed material during thedevolatilizing step (in the case of regeneration) or covert this cokeand carbon to methane (in the case of hydrogasification). In eithercase, the withdrawn solid bed material, having a reduced content of cokeand carbon as a result of regeneration or hydrogasification, may bereturned to the pre-reactor.

Any steps described herein, pertaining to the removal of solid bedmaterial from the pre-reactor vessel (either in the pre-reactor vapor orfrom the particle bed), as well as the optional separation of solid bedmaterial from char, optional regeneration, or optionalhydrogasification, together with the return of the solid bed material ina heated and/or regenerated condition, are equally applicable to theremoval of deoxygenating catalyst from the hydropyrolysis reactor vessel(either in the hydropyrolysis reactor output or from the deoxygenatingcatalyst bed). In some cases, solid bed material removed from thepre-reactor, following one or more of these optional steps, may bereturned to the hydropyrolysis reactor vessel. In other cases,deoxygenating catalyst removed from the hydropyrolysis reactor,following one or more of these optional steps, may be returned to thepre-reactor.

It may be desirable to pass the entire pretreating output, namely theentire pre-reactor vapor stream, which may have at least one improvedcharacteristic as described herein, as a result of the pretreating, tothe hydropyrolysis reactor. A representative, improved characteristicsis a reduced solid-phase chloride content relative to that of theinitial feedstock. In many cases, the yield of the pretreated feedstock,for example the yield of the total solid and/or vapor products ofpretreating (e.g., in a pre-reactor) that is passed to hydropyrolysis,can represent a substantial amount, on a weight basis, of the totalpretreating input (e.g., the total solid and/or vapor products that areinput to the pretreating step, for example to the pre-reactor). Theyield of the pretreated feedstock can be generally at least about 25% byweight (e.g., from about 25% to about 100% by weight), typically atleast about 50% by weight (e.g., from about 50% to about 100% byweight), and often at least about 70% by weight (e.g., from about 70% toabout 99% by weight).

Due to the diverse functions of the pre-reactor and wide-rangingcharacteristics of the biomass-containing feedstock, in addition to thenumber of possible types of solid bed material as described above,operating conditions in the pre-reactor may vary broadly and may includethe ranges of temperatures and pressures described below with respect tothe hydropyrolysis reactor. However, higher and lower temperatures arecontemplated for some embodiments, for example representativetemperatures may range generally from about 150° C. to about 650° C.,and typically from about 260° C. to about 540° C., depending on thespecific objective(s) of the pretreating step.

Other Pretreating Steps

As described above, aspects of the present disclosure are associatedwith processes for the effective conversion of MSW and otherbiomass-containing initial feedstocks that are poorer in quality,relative to feedstocks comprising exclusively biomass, and also moredifficult to convert in processes comprising at least one hydropyrolysisstep. In representative processes comprising pretreating the initialfeedstock to produce a pretreated feedstock, the pretreated feedstockhas at least one improved characteristic over the initial feedstock. Theat least one improved characteristic may result from a pretreating stepcomprising devolatilization and/or hydropyrolysis in a pre-reactor asdescribed above. Alternatively, the at least one improved characteristicmay result from other steps (e.g., separation or classification steps)prior to hydropyrolyzing the pretreated feedstock and/or in some casesmay result from steps performed in situ, i.e., within the hydropyrolysisreactor vessel. Thus, a number of pretreating steps, as an alternativeto, or in combination with, those described above are possible.

The at least one improved characteristic may be selected from the groupconsisting of reduced non-biological material content (e.g., content ofglass, metals, and metallic oxides, including all mineral forms), ahigher temperature, a reduced average particle size, a reduced averageparticle aerodynamic diameter, an increased average particle surfacearea to mass ratio, a more uniform particle size, a reduced corrosivespecies content, a reduced hydropyrolysis catalyst poison content (e.g.,reduced sodium), and a reduced hydroconversion catalyst poison content.

[98] According to particular embodiments, the pretreating of the initialfeedstock may comprise removing at least a portion of the non-biologicalmaterials. For example, the pretreated feedstock may have a reducedcontent, relative to the initial feedstock, of one or more of animpurity selected from the group consisting of (A) total chloride, (B)total plastics, (C), total glass, (D) total metals (with representativemetals as defined above, in their elemental forms and/or present ascompounds, e.g., in their oxide and mineral forms), and (E) combinedtotal nitrogen and sulfur content. According to representativeembodiments, the pretreated feedstock can have a content of one or moreof (A), (B), (C), (D), and/or (E) that is reduced generally by at leastabout 10% by weight (wt-%) (e.g., from about 10% wt-% to about 99%wt-%), typically by at least about 25 wt-% (e.g., from about 25 wt-% toabout 98 wt-%), and often by at least about 50 wt-% (e.g., from about 50wt-% to about 95 wt-%) relative to that of the initial feedstock.According to various embodiments, the performance of the pretreatingstep may be characterized by any of the above-recited ranges of yieldsin combination with any of the above-recited ranges of reduction in oneor more impurities selected from the group consisting of (A), (B), (C),(D), and (E) (e.g., a pretreated feedstock yield of at least about 70wt-%, in combination with a reduction in total plastics in an amountfrom about 50 wt-% to about 95 wt-%).

Representative initial feedstocks, for example, can comprise totalchloride (measured as elemental Cl) in an amount generally of at leastabout 200 parts per million (ppm) (e.g., from about 200 ppm to about10,000 ppm), typically at least about 500 ppm (e.g., from about 500 ppmto about 7,500 ppm), and often at least about 1000 ppm (e.g., from about1000 ppm to about 5,000 ppm). Particular feedstocks, such as algae grownin salt water, may have high levels of both chloride and sodium. In theenvironment of an integrated hydropyrolysis process, chloride canpotentially form aqueous hydrochloric acid, and sodium can act as apoison that deactivates catalysts having hydrotreating activity, asdescribed above. Algae can therefore significantly benefit from apretreatment step in which levels of both chloride and sodium arereduced (e.g., according to the above-recited ranges of reduction inthese impurities).

Representative plastics that may be present in initial feedstocks (e.g.,MSW) include polyvinylchloride, polyolefins (e.g., polyethylene,including high density polyethylene (HDPE) and low density polyethylene(LDPE); polypropylene; polybutylene; and polyolefin co-polymers),polyesters (e.g., polyethylene terephthalate, polybutyleneterephthalate, and polyester co-polymers), polyamides (e.g.,polycaprolactam), poly(meth)acrylates, polyalkyl oxides (e.g.,polyethylene oxide), polyvinyl alcohol homo- and copolymers (e.g., PVAfoams, polyethylene vinyl alcohol), polyethylene glycol homo- andcopolymers, polyoxamers, polysiloxanes (e.g., polydimethylsiloxane),polyethyloxazoline, and polyvinyl pyrrolidone, as well as hydrogels suchas those formed from crosslinked polyvinyl pyrrolidinone and polyesters(e.g., polyvinyl pyrrolidone/cellulose esters and polyvinylpyrrolidone/poly urethane), acrylic polymers (e.g., methacrylate) andcopolymers, vinyl halide polymers and copolymers (e.g., polyvinylchloride), polyvinyl ethers (e.g., polyvinyl methyl ether),polyvinylidene halides (e.g., polyvinylidene fluoride and polyvinylidenechloride), polyacrylonitrile, polyvinyl ketones, polyvinyl aromatics(e.g., polystyrene), polyvinyl esters (e.g., polyvinyl acetate),copolymers of vinyl monomers with each other and olefins (e.g.,ethylene-methyl methacrylate copolymers, acrylonitrile-styrenecopolymers, ABS resins and ethylene-vinyl acetate copolymers), alkydresins, polycarbonates, polyoxymethylenes, polyimides, polyethers, epoxyresins, rayon, rayon-triacetate, and combinations thereof. Based on EPAinformation (see, for example,http//www.epa.gov/epawaste/nonhaz/municipal/index.htm) representativeMSW may have plastics of any of the following types and/or amounts,based on the total amount of plastics: polyethylene terephthalate in therange from about 5% to about 25% by weight, high density polyethylene inthe range from about 5% to about 30% by weight, polyvinyl chloride inthe range from about 1% to about 10% by weight, low density polyethylenein the range from about 10% to about 35% by weight, polypropylene in therange from about 12% to about 40% by weight, and/or polystyrene in therange from about 3% to about 15% by weight.

Representative pretreating steps may involve the classification ofparticles of the initial feedstock into relatively higher and lowerquality fractions, with the higher quality fraction having the at leastone improved characteristic, as described above. According to aparticular embodiment, for example, pretreating can comprise separatingthe initial feedstock into at least first and second fractions havingcontents of plastic that are lower and higher, respectively, compared tothe content of plastic of the initial feedstock. The first fraction maytherefore be substantially devoid of plastic (or otherwise have areduction in total plastic content as described above), whereas thesecond fraction may comprise a substantial amount of plastic.

Representative particle separations or classifications that may beperformed to provide fractions of solid particles of differing densities(e.g., by virtue of having differing contents of plastics) includeseparations utilizing, for example, contacting of the solid particleswith separating liquids or the use of a centrifuge. Sorting of solidparticles using a flowing gas stream (e.g., in a pneumatic separator) toprovide fractions of differing densities or differing fluid dynamicproperties in general, and thereby having at least one improvedcharacteristic as described above, is also possible. Such sorting can beused, for example, to provide a pretreated feedstock having particleswith a reduced average particle aerodynamic diameter, an increasedaverage particle surface area to mass ratio, a more uniform particlesize, and/or even a reduced non-biological material content. Accordingto one representative embodiment, a pre-treating step may comprisecontacting the biomass-containing feedstock with a flowing stream of gas(e.g., air) to separate less dense materials (e.g., wood- and/orpaper-based particles) in a fraction with a desired characteristic(e.g., a reduced non-biological material content) for furtherprocessing. In the case of any separation based on density or otherfluid dynamic property, the biomass-containing feedstock may beappropriately re-sized (e.g., chopped or ground) to form particles thatare more amenable to a given separation. Different fractions of thebiomass-containing feedstock, obtained from sorting, may be fed to apre-reactor or hydropyrolysis reactor at differing locations and/orusing different solid particle transport equipment.

According to some embodiments, the first fraction, having an improvementin at least one characteristic (e.g., a reduced total plastics content)may represent the pretreated feedstock that is subsequently subjected tothe hydropyrolyzing step, whereas the second fraction may be subjectedto further processing steps, recycled (at least partly) to thepretreating step, or used for a different purpose (e.g., plasticsrecovery and recycling). Alternatively, the second fraction may also bepassed to the hydroprocessing reactor vessel, albeit at a differentlocation and/or in a different manner, relative to the first fraction.For example, a representative process may comprise separately feedingthe first and second fractions (e.g., having relatively lower and highercontents of total plastics, as described above) to the hydropyrolysisreactor vessel at separate locations (e.g., differing axial heights).The particular locations, to which the fractions are separatelyintroduced, may be associated with localized conditions (e.g.,temperature, gas velocity, solids concentration, average particle size)that are compatible with the compositions of the first and secondfractions. According to other embodiments, the first and secondfractions may be introduced to the hydropyrolysis reactor usingintroduction techniques that are compatible with the compositions of thefirst and second fractions. For example, a first fraction having arelatively lower content of total plastics may be fed to thehydropyrolysis reactor vessel through a cooled screw assembly, whereasthe second fraction having a relatively higher content of total plasticsmay be fed to this reactor vessel through a heated extruder. In any ofsuch embodiments, the first and second fractions may, in combination,represent all or a part of the initial feedstock, for example, thesefractions in combination may represent a yield of the pretreatedfeedstock in the ranges given above (with some portion, e.g., a thirdfraction, that is not used in the hydropyrolysis reactor vessel).

Representative glasses that may be present in initial feedstocks (e.g.,MSW) include E-glasses, boron-free E-glasses, S-glasses, R-glasses,AR-glasses, rare earth-silicate glasses, Ba—Ti-silicate glasses,nitrided glasses such as Si-AI-O—N glasses, A-glasses, C-glasses andCC-glasses. Each of these glass types are known in the art, particularlywith respect to the compositions they embrace.

Representative initial feedstocks can comprise metals such as Li, Be,Na, Mg, Al, Si, P, K, Ca, Ti, V, Cr, Mn, Fe, Co, Ni, Cu, Zn, Mo, Sn, W,Pb, and/or Hg that are present in elemental form or as metal compoundssuch as metal oxides, including all mineral forms. These metals may bepresent in the initial feedstock in a combined amount of generally atleast about 0.1% by weight (wt-%) (e.g., from about 0.1 wt-% to about 10wt-%), typically at least about 0.5 wt-% (e.g., from about 0.5 wt-% toabout 7.5 wt-%), and often at least about 1 wt-% (e.g., from about 1wt-% to about 5 wt-%). The above ranges with respect to the content ofmetals in the initial feedstock are also applicable to the content ofash. The ash content refers to the percentage by weight of the initialfeedstock that does not combust at a temperature of 750° C. The ash isgenerally in the form of metallic oxides (e.g., silica), and representsa specific type of non-biological material that is present in biomassgenerally and consequently also present in biomass-containing feedstockssuch as MSW, but often at a higher concentration than in the biomassportion of the feedstock alone.

Initial feedstocks can comprise a total combined amount of nitrogen andsulfur (measured as total elemental N and S) of at least about 100 ppm(e.g., from about 100 ppm to about 30,000 ppm), typically at least about500 ppm (e.g., from about 500 ppm to about 25,000 ppm), and often atleast about 1000 ppm (e.g., from about 1000 ppm to about 20,000 ppm).According to various embodiments, representative initial feedstocks canhave any of the above-recited ranges of non-biological material, totalchloride, total ash, and/or total N and S, in combination (e.g., atleast about 5 wt-% of non-biological material and from about 1000 ppm toabout 5000 ppm total chloride).

Solid sorbents in the pre-reactor, or otherwise used in situ in thehydropyrolysis reactor vessel, may be used for scavenging corrosivespecies and/or species that negatively impact the activity of thedeoxygenating catalyst and/or hydroconversion catalyst. According toparticular embodiments, the pretreated feedstock has an improvedcharacteristic of a reduced content of total chloride, a reduced contentof total metals, or a reduced content of both total chloride and totalmetals, and the step of pretreating comprises contacting the initialfeedstock with a solid sorbent under pretreating conditions wherebychloride and/or metals present in the initial feedstock are adsorbedonto the solid sorbent. Suitable sorbents having both capacity foradsorbing chloride and the ability to withstand elevated temperaturesassociated with devolatilization and/or pyrolysis in the pre-reactorand/or hydropyrolysis reactor, include, for example, calcium carbonate(CaCO₃) and other minerals containing basic anions such as carbonate andhydroxide. Such solid sorbents may be suitable in a pre-reactor orotherwise in the hydropyrolysis reactor to provide the improvedcharacteristics of reduced total chloride and/or reduced total metals(e.g., reduced sodium) in situ.

According to an alternative embodiment, the biomass-containing feedstockmay be subjected to a simple leaching step (e.g., by contacting it withan aqueous solution under batch conditions or with continuous flow ofthe solution) to remove water-soluble chlorides and/or other potentiallycorrosive or detrimental species. The resulting pretreated feedstockobtained in this manner may have an improved characteristic of reducedtotal chloride and/or reduced total metals (e.g., present in the initialfeedstock in the form of water-soluble metal salts). Such a pretreatedfeedstock may be dried prior to hydropyrolysis or otherwise introducedinto the hydropyrolysis reactor without drying, or even introduced in aslurry form. The pretreated feedstock may otherwise be introduced in dryform, water-saturated form, or slurry form, to a pre-reactor asdescribed herein, upstream of a hydropyrolysis reactor. Any aqueouseffluent obtained from such a leaching step may then be contacted underappropriate conditions (e.g., ambient conditions of temperature andpressure) with a suitable ion exchange resin or other solid sorbent,having the capacity to remove the leached, water-soluble species andpurify the aqueous effluent.

In a particular embodiment in which the content of ash or othernon-biological material is reduced in the pretreated feedstock relativeto that of the initial feedstock, the step of pretreating comprisesdevolatilizing the initial feedstock in a fluidized bed, with theremoval of non-biological material at one or more drawoff locationscorresponding to one or more axial heights in the fluidized bed.Therefore, to the extent that a fluidized bed of a pre-reactor orhydropyrolysis reactor can act to separate or classify different typesof solid particles (e.g., particles having different densities) intoregions within the fluidized bed, the removal of solid particles atselected drawoff locations (e.g., where particles having a given desiredor undesired characteristic are selectively enriched) advantageouslyallows for the selective removal of particles having such desired orundesired characteristic(s). For example, the selective removal ofparticles having undesired characteristics such as a high ash or othernon-biological material content provides a pretreated feedstock havingthe improved characteristic of reduced ash content or reducednon-biological material content, remaining in the reactor.Alternatively, particles having a desired characteristic such as a moreuniform particle size, may be selectively removed from the fluidized bedwithin the reactor to provide the pretreated feedstock. According to onerepresentative method of classifying or concentrating different types ofsolid particles (e.g., solid particles of differing densities and/ordiffering aerodynamic diameters), differing superficial gas velocitieswith the pre-reactor vessel may be used. These differing gas velocitiescan be achieved by varying the cross-sectional area at differing axialheights, while maintaining a fixed gas volumetric flow rate, and/orotherwise by adding (injecting) gas at differing axial locations whilemaintaining a fixed cross-sectional area. A combination of varyingcross-sectional area and gas injection at a given axial height may alsobe used.

The removal of non-biological material from a particular location orlocations can also prevent the accumulation of such material, which canlead to disruption in the action and function of the bed of solidmaterial. According to some embodiments, the removal of solid materialscan also occur upstream of the pre-reactor (e.g., by physical sorting orthe use of a flowing gas separation systems, such as a pneumaticseparator), within the pre-reactor, within the hydropyrolysis reactorvessel (in situ), or even downstream of the hydropyrolysis reactorvessel but upstream of a hydroconversion reactor vessel, resulting inthe same or a similar effect of reducing the content of a non-biologicalmaterial in the initial feedstock (in this case the content ofnon-biological material in the feedstock to any of the pre-reactorvessel, the hydropyrolysis reactor vessel, or possibly even thehydroconversion reactor vessel).

A number of other types of separations and classifications may beperformed to adjust the fluid dynamic properties of the initialfeedstock, prior to or during its use in a fluidized bed hydropyrolysisreactor vessel. Therefore, for example, improved characteristics of apretreated feedstock, such as a reduced average particle size, a reducedaverage particle aerodynamic diameter, an increased average particlesurface area to mass ratio, and/or a more uniform particle size, may bebeneficial in maintaining good fluidization parameters (e.g., in termsof the superficial gas velocity needed for fluidization) of thepretreated feedstock. The improvement of the feedstock along any ofthese lines may also have the added benefit of upgrading MSW, algae,lemna, or other biomass-containing feedstock in terms of itscomposition. For example, increasing the average particle surface areato mass ratio can refer to an aerodynamic separation in which metallicobjects and other particles of a low surface area to mass ratio areselectively removed in the pretreated feedstock relative to the initialfeedstock, leaving an increased content of higher surface area to massratio particles, such as wood particles, in the pretreated feedstock. Inthis manner, a separation resulting in increasing the average particlesurface area to mass ratio, or improving any of the other fluid dynamicproperties as described above, may have the added benefit of reducingthe content of non-biological materials in the pretreated feedstock.

The adjustment of fluid dynamic properties of particles can, accordingto some embodiments, occur in situ (e.g., within the hydropyrolysisreactor vessel, or within a pre-reactor vessel used to devolatilize thefeedstock), particularly with respect to disrupting the formation ofagglomerated particles of the biomass-containing feedstock. Particleagglomerates can form, for example, as a result of a high content ofplastics that, when softened or melted, can coat particles of thefeedstock and/or other solid particles, causing them to stick together(agglomerate). The improved characteristics of reduced average particlesize and/or more uniform particle size, as described above, as well asother improved fluid dynamic properties, can, according to someembodiments, refer to improvements relative to the initial feedstock inits agglomerated or partially agglomerated state under processingconditions in the pre-reactor vessel or hydropyrolysis reactor vessel.The improved characteristic, as a result of taking positive steps toeither break agglomerated feedstock particles or otherwise prevent theformation of such agglomerates in the first place, may therefore bebased on the improvement over the hypothetical situation that wouldoccur in the absence of such steps. Accordingly, in some embodiments,the step of pretreating an initial feedstock to produce a pretreatedfeedstock having at least one improved characteristic over the initialfeedstock may be satisfied by remediation (e.g., agitation to breakparticle agglomerates or prevent their formation) that is performed insitu, i.e., in the pre-reactor vessel or hydropyrolysis reactor vessel.

More generally, such remediation steps can be used to breakagglomerates, or prevent the formation of agglomerates, of anyinteracting solid particles within the pre-reactor or hydropyrolysisreactor, including agglomerates of (i) particles of feedstock, (ii)particles of feedstock with particles of solid bed material, particlesof catalyst, and/or particles of char, (iii) particles of solid bedmaterial, (iv) particles of catalyst, and/or (v) particles of char.According to particular embodiments, the pretreating and/orhydropyrolyzing steps may be operated with continuous, intermittent, orlocalized high agitation conditions that reduce the formation of any ofthese types of agglomerates. Such high agitation conditions, forexample, can reduce the formation of agglomerates of particles ofdeoxygenating catalyst in the hydropyrolysis reactor vessel. The use ofspecific gas velocities may be tailored to the properties of theagglomerates (e.g., the average particle size and/or particle sizedistribution of agglomerates of particles of the deoxygenating catalystin the hydropyrolysis reactor vessel) that are broken apart, or thatotherwise form in the absence of the high agitation conditions.According to some embodiments, the use of high fluidization gasvelocities alone may be sufficient to break particle agglomerates orprevent their formation and thereby achieve the desired degree ofremediation. Otherwise, the selected size ranges of bed material and/orfeedstock may be used, such that, under processing conditions,interactions of the selected size ranges of the particles promote thedesired degree of remediation.

According to particular embodiments, high agitation conditions,effective for breaking particle agglomerates or otherwise preventingtheir formation, can include localized use, either continuously orintermittently, of a gas velocity that significantly exceeds (e.g., by afactor of at least about 2, at least about 5, or at least about 10) theoverall superficial velocity of fluidizing gas in the pre-reactor vesselor the hydropyrolysis reactor vessel, or otherwise the overall averagesuperficial velocity of fluidizing gas in the fluidized particle beds ofthese respective reactor vessels (e.g., in the case of a reactor havinga varying cross-sectional area). For example, the overall superficialvelocity of the fluidizing gas may be calculated as the total volumetricflow rate of the fluidizing gas, divided by the average cross-sectionalarea of the reactor or of the associated, solid particle bed, which maybe a fluidized bed, within the reactor vessel. Localized, high gasvelocities can be created using gas injection nozzles in the desiredareas where agglomerated particles are susceptible to formation and/orbreakage. High agitation conditions can also be enhanced using internalstructures (e.g., baffles or impact plates) in combination with gasinjection nozzles, which structures and nozzles may be positioned incombination to subject agglomerated particles to impact forcessufficient for their breakage and/or the prevention of agglomerationfrom the outset, or at least the prevention of the further growth offormed agglomerates.

Hydropyrolyzing the Pre-Reactor Vapor or Other Pretreated Feedstock

Subsequent to contacting the biomass-containing feedstock with a carbondioxide-containing gas and/or hydrogen-containing gas (or otherpre-reactor gas as described above), in a pre-reactor vessel containinga solid bed material, representative processes can includehydropyrolyzing at least a portion (i.e., some or all) of thepre-reactor process vapor stream, as described above, or otherwisehydropyrolyzing at least a portion of a pretreated feedstock, asdescribed above.

In embodiments in which a pre-reactor is used for pretreatment, thepre-reactor may effect devolatilization and/or at least some pyrolysis(e.g., hydropyrolysis) of the biomass-containing feedstock. In general,deoxygenation reactions will not occur to any significant extent, asthese are reserved primarily for the hydropyrolysis reactor vessel and asubsequent hydroconversion reactor vessel (if used). Those skilled inthe art, consulting the present disclosure, will appreciate theoperating conditions in the pre-reactor required to achieve a givenextent of devolatilization and/or hydropyrolysis, including temperature,hydrogen partial pressure, and feedstock residence time. Due to thesignificant extent of deoxygenation in the hydropyrolysis reactor vesseland optional hydroconversion reactor vessel, the associatedhydropyrolyzing and hydroconverting steps are normally both exothermic,i.e., the reactions associated with these steps involve a net generationof heat, despite the pyrolysis reactions in isolation being endothermic.In contrast, due to the relatively low extent of hydroconversion (or insome cases no hydroconversion), occurring in the pre-reactor vessel, thedevolatilization and optional pyrolysis in the step of devolatilizing isgenerally endothermic, i.e., the reactions associated with this stepinvolve a net consumption of heat. In order to effectively manage thereaction thermodynamics of both the pre-reactor and hydropyrolysisreactor vessel, the temperature of the pre-reactor vapor stream (orportion thereof that is introduced into the hydropyrolysis reactor) maybe adjusted upward or downward, to meet the temperature requirements ofthe hydropyrolysis reactor. For example, according to one embodiment,the temperature of the pre-reactor vapor stream or portion thereof isadjusted to the mean temperature, or to within about 10° C. of the meantemperature, of the hydropyrolysis reactor over a short time period(e.g., in less than about 2 minutes or even in less than about 1minute).

In view of the above considerations, if a catalyst is used as the solidbed material in the pre-reactor, suitable catalysts for such purpose mayinclude those having a relatively lower deoxygenation activity, comparedto catalysts used in the hydropyrolysis reactor vessel and/orhydroconversion reactor vessel. According to some embodiments, spent orpartially spent catalyst from the hydropyrolysis reactor and/orhydroconversion reactor (e.g., following some period of use inhydropyrolyzing and/or hydroconversion steps) may advantageously be usedin the pre-reactor, to provide a catalyst having a desired level ofdeoxygenation activity. According to specific embodiments, therefore,the solid bed material in the pre-reactor vessel may comprise, consistessentially of, or consist of spent or partially spent deoxygenatingcatalyst previously used in the hydropyrolysis reactor vessel and/orspent or partially spent hydroconversion catalyst previously used in thehydroconversion reactor vessel.

According to particular embodiments, therefore, the solid bed materialin the pre-reactor may comprise a spent or partially spent deoxygenatingcatalyst transferred from the hydropyrolysis reactor, a spent orpartially spent hydroconversion catalyst transferred from thehydroconversion reactor, or a combination thereof. For example, thespent or partially spent catalyst(s) may be continuously removed fromone or both of these reactor vessels and fed to the pre-reactor vesselto derive additional, beneficial use from the catalyst(s) in pretreatingthe feedstock. It should be appreciated that, in some embodiments, thecatalyst particle sizes for the pre-reactor, hydropyrolysis reactor, andhydroconversion reactor are not necessarily compatible, particularly incases of the different reactors operating under different regimes offluidized bed (e.g., for the pre-reactor and/or hydropyrolysis reactor)and fixed bed (e.g., for the hydroconversion reactor) processing.Therefore, the use of spent or partially spent catalyst in thepre-reactor vessel may require re-sizing, for example by grinding orcrushing to achieve an average particle size that is suitable for use inthe pre-reactor.

The references to “spent or partially spent” deoxygenating catalystsrefer to catalysts having activity for deoxygenation that is reduced,relative to the same catalyst in its unused (fresh) state. A loss ofdeoxygenation activity can be verified by comparative testing in acontrolled environment, in which the reaction temperature required toachieve a given extent of deoxygenation of a test feedstock provides ameasure of catalyst activity. A higher reaction temperature isindicative of lower activity. The condition of a deoxygenating catalystthat results in an at least partial loss of activity, rendering it spentor partially spent and therefore suitable in some embodiments for use ina pre-reactor, may result from coking, contamination with impurities(e.g., metals), or another condition leading to activity loss. Thecondition may be reversible (e.g., through catalyst regeneration and/orcatalyst sulfiding) or irreversible.

The hydropyrolyzing step can occur in a hydropyrolysis reactor vesselcontaining hydrogen and a deoxygenating catalyst, in order to produce ahydropyrolysis reactor output comprising at least one non-condensablegas, a partially deoxygenated hydropyrolysis product and char particles.In many cases, the hydropyrolysis reactor output will comprise, asnon-condensable gases, one or more of H₂, CO, CO₂, CH₄, C₂H₆, and C₂H₄.However, depending on the methanation activity and water-gas shiftconversion activity of the deoxygenating catalyst, more or less methane(CH₄) will be produced at the expense of CO, CO₂, and H₂. In highlymethanating environments, it may be possible for the hydropyrolysisreactor output to comprise little or no CO and/or CO₂ as non-condensablegases (e.g., in an amount of less than 5 vol-%, or even less than 1vol-%, of all non-condensable gases) but nevertheless still comprise oneor more of H₂, CH₄, C₂H₆, and C₂H₄.

In general, therefore, the hydropyrolysis reactor output will comprise(i) CO₂, CO and other non-condensable or low molecular weight gases(e.g., C₁-C₃ hydrocarbon gases, including both paraffinic and olefinichydrocarbons), together with any stoichiometric excess of H₂ that is notconsumed in the hydropyrolysis reactor, (ii) a partially deoxygenatedhydropyrolysis product (e.g., in the form of a condensable vapor), and(iii) solid char particles. As used herein, the “partially deoxygenatedhydropyrolysis product” of the hydropyrolyzing step may compriseoxygenated hydrocarbons (e.g., derived from cellulose, hemicellulose,and/or lignin) that may be subjected to more complete deoxygenation(e.g., to produce hydrocarbons and remove the oxygen in the form of CO,CO₂, and/or water) in a subsequent hydroconversion process. The term“partially deoxygenated hydropyrolysis product,” however, does notpreclude the presence of some amount of hydrocarbons (e.g., aromatichydrocarbons such as alkylbenzenes) that are fully deoxygenated and thuscannot be further deoxygenated. The partially deoxygenatedhydropyrolysis product, according to some embodiments, will generallycontain a lower oxygen content compared to conventional bio-oilsobtained from pyrolysis in the substantial absence of any deoxygenationreactions. This is due to the extent of catalytic deoxygenationreactions occurring within the hydropyrolysis reactor in the presence ofhydrogen. Representative oxygen contents of the partially deoxygenatedhydropyrolysis product are generally in the range from about 2% to about30% by weight, and typically in the range from about 5% to about 25% byweight.

As in the case of the pre-reactor vessel, described above, thehydropyrolysis reactor vessel may contain a fluidized bed, but in thiscase including the deoxygenating catalyst. Other solids in thisfluidized bed may include the pretreated feedstock or solids present inthe pre-reactor vapor stream, or otherwise present in the portion of thepre-reactor vapor stream that is passed from the pre-reactor vessel tothe hydropyrolysis reactor vessel. Accordingly, the hydropyrolyzing stepmay be performed using a fluidized bed of the deoxygenating catalyst,and the hydropyrolysis fluidization gas may comprise at least theportion of the pre-reactor process vapor stream that is hydropyrolyzed,subsequent to being generated in the pre-reactor vessel. Representativesuperficial gas velocities for the hydropyrolysis fluidization gas rangegenerally from about 0.03 meters/second (m/s) to about 6 m/s, typicallyfrom about 0.15 m/s to about 3 m/s, and often from about 0.3 m/s toabout 1.5 m/s.

Following the hydropyrolyzing step, representative processes may furthercomprise removing all or substantially all of the char particles and/orother solid particles (e.g., catalyst fines) from the hydropyrolysisreactor output to provide a purified hydropyrolysis reactor vapor streamhaving a reduced char content. The removal of char particles, such asthose which may be entrained in the pre-reactor vapor stream, may beparticularly important in processes in which the products ofhydropyrolysis, including the purified hydropyrolysis product vaporstream or a portion thereof, are subjected to a fixed bed catalyticconversion process. In such cases, the removal of fine char particlesprevents problems associated with premature plugging of the fixed bed asthe char particles become trapped within the voids of the fixed catalystbed. As defined herein, the removal of substantially all of the charparticles means that at least 99% by weight of the char particles in thehydropyrolysis reactor output are excluded from the purifiedhydropyrolysis product vapor stream. According to further embodiments,at 99.9% by weight, or at least 99.99% by weight, of the char particlesare excluded.

Representative processes may further comprise hydroconverting at least aportion of the purified hydropyrolysis reactor vapor stream in ahydroconversion reactor vessel containing hydrogen and a hydroconversioncatalyst, producing a hydroconversion reactor output. The purifiedhydropyrolysis reactor vapor stream, like the hydropyrolysis reactoroutput, may include condensable gases (e.g., water vapor; C₃H₈, C₃H₆,and higher molecular weight hydrocarbons; and oxygenated hydrocarbonssuch as phenols) as well as non-condensable gases (e.g., H₂, CO, CO₂,CH₄, C₂H₆, and C₂H₄). Generally, the purified hydropyrolysis reactorvapor stream, or at least a portion thereof, will be passed completelyin the vapor phase to a subsequent hydroconverting step, withoutintermediate condensing of any portion of this stream. However,intermediate condensing with re-heating may also be possible, forexample, to selectively condense unwanted components of relatively lowvolatility (relatively high boiling point), optionally providing aliquid condensate “wash” for removing char and/or other solid particles(e.g., catalyst fines). In other embodiments, the purifiedhydropyrolysis reactor vapor stream may be partially condensed andpassed as a mixed vapor and liquid phase to the subsequenthydroconverting step. Partial condensation may occur, for example, whenheat is recovered from the purified hydropyrolysis reactor vapor stream(e.g., by heat exchange with a cooler stream), or when heat is otherwiselost to the environment.

As is apparent from the above description, all or a portion of thepurified hydropyrolysis reactor vapor stream exiting the hydropyrolysisreactor (and obtained following the substantial removal of all charparticles) may be subjected to the subsequent hydroconverting step.Between the steps of hydropyrolyzing and hydroconverting, therefore, thepurified hydropyrolysis reactor vapor stream may, by separation orreaction, be enriched with respect to one or more desired componentsand/or depleted with respect to one or more undesired components. Thepurified hydropyrolysis reactor vapor stream may also be mixed prior toor during the hydroconverting step with one or more additional streams.Accordingly, unless otherwise noted, the step of hydroconverting atleast a portion of the purified hydropyrolysis reactor vapor stream ismeant to encompass such intermediate steps as separation, reaction,and/or mixing. In some embodiments, however, the purified hydropyrolysisreactor vapor stream, or portion thereof, may be subjected to thehydroconverting step, without an intermediate step of being enrichedwith respect to one or more desired components and/or depleted withrespect to one or more undesired components, by separation or reaction(e.g., in the case of partial condensation, which may serve to removesome of the solid particles). For example a portion of the purifiedhydropyrolysis reactor vapor stream may be split from the entireeffluent of the hydropyrolysis reactor (and following the substantialremoval of all char particles), with little or no change in itscomposition. Likewise, the purified hydropyrolysis reactor vapor stream,or portion thereof, may be subjected to the hydroconverting step,without being mixed prior to or during the hydroconverting step with oneor more additional streams. However, in many cases it will be desirableto mix the purified hydropyrolysis reactor vapor stream or portionthereof with hydrogen or a hydrogen-containing gas stream that providesadditional hydrogen (beyond that contained in the purifiedhydropyrolysis reactor vapor stream or portion thereof) forhydroconversion as described below.

Suitable catalysts for use in the pre-reactor (in the case of the solidbed material having catalytic activity), hydropyrolysis reactor, and/orhydroconversion reactor will in general have activity forhydroprocessing of the biomass-containing feedstock, the pretreatedfeedstock, and/or their hydropyrolysis reaction products, in anenvironment of suitable hydrogen partial pressure, temperature, andother conditions as described herein. Hydroprocessing is meant toencompass broadly a number of possible reactions, includinghydrotreating, hydrocracking, hydroisomerization, and combinationsthereof, as well as possible oligomerization occurring under ahydrogen-rich environment. Representative hydroprocessing catalystsinclude those comprising at least one Group VIII metal, such as iron,cobalt, and nickel (e.g., cobalt and/or nickel) and at least one GroupVI metal, such as molybdenum and tungsten, on a high surface areasupport material such as a refractory inorganic oxide (e.g., silica,alumina, titania, and/or zirconia). A carbon support may also be used. Arepresentative catalyst having hydroprocessing activity thereforecomprises a metal selected from the group consisting of nickel, cobalt,tungsten, molybdenum, and mixtures thereof (e.g., a mixture of nickeland molybdenum), deposited on any of these support materials, orcombinations of support materials. The choice of support material may beinfluenced, in some cases, by the need for corrosion resistance in viewof the possibility of forming condensed aqueous acids, for example acidsknown to be present in bio-oils obtained from conventional biomasspyrolysis and/or acids obtained from the hydrogenation of impurities inthe biomass-containing feedstock (e.g., chlorides), as described herein.

The Group VIII metal is typically present in the hydroprocessingcatalyst in an amount ranging from about 2 to about 20 weight percent,and normally from about 4 to about 12 weight percent, based on thevolatile-free catalyst weight. The Group VI metal is typically presentin an amount ranging from about 1 to about 25 weight percent, andnormally from about 2 to about 25 weight percent, also based on thevolatile-free catalyst weight. A volatile-free catalyst sample may beobtained by subjecting the catalyst to drying at 200-350° C. under aninert gas purge or vacuum for a period of time (e.g., 2 hours), so thatwater and other volatile components are driven from the catalyst.

Other suitable hydroprocessing catalysts include zeolitic catalysts, aswell as noble metal catalysts where the noble metal is selected frompalladium and platinum. Two or more hydroprocessing catalysts of thesame or different type may be utilized in the pre-reactor vessel, thehydropyrolysis reactor vessel, and/or the hydroconversion reactor vesselor combination of hydroconversion zone vessels (described more fullybelow) that provide the substantially fully deoxygenated hydrocarbonliquid. For example, different hydroprocessing catalysts may be usefulfor catalyzing deoxygenation (e.g., in a hydropyrolysis reactor vessel)or hydrocracking (e.g., in a hydroconversion reactor vessel). In somecases, the catalyst and conditions in a hydroconversion reactor vesselmay be chosen for their effectiveness in catalyzing hydrocracking,thereby enhancing the yield of hydrocarbons of a desired molecularweight (e.g., gasoline boiling-range hydrocarbons). The catalyst andconditions in a hydroconversion reactor vessel may also be chosen fortheir effectiveness in catalyzing hydroisomerization, thereby enhancingthe yield of isoparaffins, which can improve the quality of thesubstantially fully deoxygenated hydrocarbon liquid, or at least adiesel fuel boiling-range fraction thereof, in terms of reducing itspour point and cloud point temperatures.

Representative hydrocracking catalysts include those described in U.S.Pat. No. 6,190,535 and U.S. Pat. No. 6,638,418, incorporated byreference herein with respect to their disclosures of these catalysts.Other suitable hydrocracking catalysts include those comprising a metalselected from the group consisting of iron, nickel, cobalt, tungsten,molybdenum, vanadium, ruthenium, and mixtures thereof, deposited on azeolite. Representative zeolites for hydrocracking catalyst supports mayinclude beta zeolite, Y zeolite and MFI zeolite. The structures of Yzeolite and MFI zeolite are described, and further references areprovided, in Meier, W. M, et al., Atlas of Zeolite Structure Types,4^(th) Ed., Elsevier: Boston (1996). Representative hydroisomerizationcatalysts include those described in US 2009/0077866 as “isomerizationcatalysts.” The contents of US 2009/0077866 with respect to suchisomerization catalysts are hereby incorporated by reference.

As is understood in the art, the term “hydrotreating catalyst”encompasses catalysts having activity for any of hydrodeoxygenation oforganic oxygen-containing molecules to form water; decarbonylation ordecarboxylation of organic oxygen-containing molecules to form CO andCO₂, respectively; hydrodenitrification of organic nitrogen-containingmolecules; and/or hydrodesulfurization of organic sulfur-containingmolecules. Representative catalysts useful in the pre-reactor vessel,hydropyrolysis reactor vessel, and/or at least one hydroconversionreactor vessel, therefore include hydrotreating catalysts as describedin U.S. Pat. No. 6,190,535 and U.S. Pat. No. 6,638,418, incorporated byreference herein with respect to their disclosures of these catalysts.In a representative embodiment, the catalytically active metals (e.g.,nickel and molybdenum) may be the same in catalysts that are used in twoor more of the pre-reactor vessel, hydropyrolysis reactor vessel, and atleast one hydroconversion reactor vessel, with the support materials forthe catalysts also being the same. Alternatively, the support materialsmay vary with respect to their acidity, in order to provide varyingdegrees of hydrocracking functionality. For example, the supportmaterial used for a catalyst in the hydropyrolysis reactor vessel may bea relatively low acidity material (e.g., an alumina-phosphorous mixture)while the support material used for a catalyst in the hydroconversionreactor vessel may be a relatively high acidity material (e.g., anamorphous or zeolitic silica-alumina), thereby improving the tendency ofthe hydroconversion reaction zone to catalyze cracking reactions, if areduction in the molecular weight of hydrocarbons in the substantiallyfully deoxygenated liquid hydrocarbon product is desired. Acidity may bedetermined, for example in units of moles of acid sites per gram ofcatalyst, by temperature programmed desorption (TPD) of a quantity ofammonia, from an ammonia-saturated sample of the catalyst, over atemperature from 275° C. to 500° C., which is beyond the temperature atwhich the ammonia is physisorbed. The quantity of acid sites thereforecorresponds to the number of moles of ammonia that is desorbed in thistemperature range.

Representative processes may further comprise recovering a substantiallyfully deoxygenated hydrocarbon liquid and a gaseous mixture from thehydroconversion reactor output. In this regard, the hydroconversionreactor output may comprise condensable gases from which thesubstantially fully deoxygenated hydrocarbon liquid (which may includeone, or a mixture of, substantially fully deoxygenated higher valueliquid products) may be condensed and then separated using one or moreseparation processes including phase separation from a condensed aqueousphase and/or distillation. For example, phase separation may be used torecover the substantially fully deoxygenated hydrocarbon liquid from anaqueous phase comprising primarily condensed water. Distillation maythen be used, for example, to obtain substantially fully deoxygenatedhigher value liquid products such as gasoline boiling-range and/ordiesel fuel boiling-range hydrocarbon fractions. The designation of“substantially fully deoxygenated” in reference to hydrocarbon liquids,as well as higher value liquid products that may be obtained from theseliquids (e.g., by fractionation) can refer to a total oxygen content ofless than about 2% by weight, less than about 1% by weight, less thanabout 5000 ppm by weight, less than about 2000 ppm by weight, or evenless than about 1000 ppm by weight. The low oxygen content renders thesubstantially fully deoxygenated hydrocarbon liquid easily phaseseparable from condensed water. Advantageously, any net condensed waterproduced in an integrated process will have a low content of dissolvedtotal organic carbon (TOC), generally less than about 5000 wt-ppm,typically less than about 2000 wt-ppm, and often less than about 500wt-ppm.

The gaseous mixture that is recovered from the hydroconversion reactoroutput will generally include non-condensable gases (e.g., H₂, CO, CO₂,CH₄, C₂H₆, and C₂H₄) and optionally a minor amount of condensable gases(e.g., C₃ and heavier hydrocarbons), depending on the conditions (i.e.,temperature and pressure) under which the gaseous mixture is separatedfrom the hydroconversion reactor output (e.g., using a gas-liquidseparator or a stripper to achieve one or more theoretical equilibriumliquid-vapor separation stages). To the extent that this gaseous mixturecontains CO, CO₂, and hydrocarbons, at least a portion thereof may besubjected to steam reforming, in order to produce reformed hydrogen andimprove the overall hydrogen balance of the integrated process. This canadvantageously decrease or even eliminate the need for imported hydrogenobtained from the conventional reforming of hydrocarbons. According tosome embodiments, therefore, a decreased reliance on petroleum-basedcarbon sources can reduce the overall carbon footprint of thetransportation fuel fractions separated from the substantially fullydeoxygenated hydrocarbon liquid, based on a lifecycle assessment of thegreenhouse gas (GHG) emission value, according to U.S. governmentaccounting practices.

Conditions in the hydropyrolysis reactor include a temperature generallyfrom about 300° C. to about 600° C., typically from about 400° C. toabout 500° C., and often from about 410° C. to about 475° C. The weighthourly space velocity (WHSV) of the hydropyrolysis reactor, calculatedas the mass flow rate of the biomass-containing feedstock or pretreatedfeedstock divided by the catalyst inventory of the hydropyrolysisreactor vessel, is generally from about 0.1 hr⁻¹ to about 10 hr⁻¹,typically from about 0.5 hr⁻¹ to about 5 hr⁻¹, and often from about 0.8hr⁻¹ to about 2 hr⁻¹. Conditions in the hydroconversion reactor (or anyof possibly two or more hydroconversion reactors, if used) include atemperature generally from about 200° C. to about 475° C., typicallyfrom about 260° C. to about 450° C., and often from about 315° C. toabout 430° C. The weight hourly space velocity (WHSV) of thehydroconversion reactor, calculated as the mass flow rate of the feed tothe hydroconversion reactor (e.g., a purified vapor stream obtained fromthe hydropyrolysis reactor) divided by the catalyst inventory of thehydroconversion reactor vessel, is generally from about 0.01 hr⁻¹ toabout 5 hr⁻¹, typically from about 0.05 hr⁻¹ to about 5 hr⁻¹, and oftenfrom about 0.1 hr⁻¹ to about 4 hr⁻¹.

Further representative operating conditions for hydropyrolysis andhydroconversion and their significance are described in greater detailbelow. Some representative conditions are also described in U.S. patentapplication publication nos. US 2010/0251600, US 20100256428, and US2013/0338412, the contents of which are hereby incorporated by referencein their entireties.

As described in these publications, catalysts and operating conditionsin both the hydropyrolysis and hydroconversion reactor vessels may beadjusted such that the deoxygenation reactions, which remove oxygen frombiomass-derived molecules (e.g., cellulose, hemicellulose, and/orlignin), are balanced between hydrodeoxygenation, which yields H₂O, andthe non-condensable gas-yielding reactions of decarbonylation anddecarboxylation, which yield CO and CO₂, respectively. Advantageously,the production of a significant amount of these gases from biomassoxygen in turn allows for their subsequent use, in reforming of gaseousmixtures (e.g., from the hydropyrolysis reactor output and/or thehydroconversion reactor output) in which they are contained (e.g.,together with light hydrocarbons), to generate some or all of thehydrogen required in the integrated process. In the case of the use of apre-reactor as described herein, the hydrogen required for theintegrated process can include the amount of hydrogen consumed in thepre-reactor, for example if a hydrogen-containing gas is used as apre-reactor fluidizing gas, for carrying out devolatilization and/orhydropyrolysis.

According to representative embodiments, at least about 20% of theoxygen content of the biomass-containing feedstock, or at least about20% of the oxygen content of the pretreated feedstock as describedherein, is converted to CO and CO₂ following hydropyrolysis andhydroconversion, and optionally also following pretreating, includingdevolatilization. Representative ranges of conversion of the oxygencontent of the biomass-containing feedstock or pretreated feedstock toCO and CO₂ following these steps are from about 20% to about 80%, fromabout 30% to about 70%, and from about 40% to about 60%, in order toachieve a proper balancing between hydrodeoxygenation anddecarbonylation/decarboxylation, as described above. Representativeranges of conversion of this oxygen content to H₂O following these stepsare at most about 80%, from about 20% to about 80%, from about 30% toabout 70%, and from about 40% to about 60%. These ranges of feedstock orpretreated feedstock oxygen content being converted followinghydropyrolysis and hydroconversion are not necessarily representative ofthe final disposition of biomass oxygen content following downstreamconversion by steam reforming, in which the H₂O formed in hydropyrolysisand/or hydroconversion may be consumed. According to some embodiments,the final disposition of feedstock or pretreated feedstock oxygencontent to CO and CO₂, following steam reforming, may be significantlyhigher. For example, according to some embodiments in which the processis integrated with steam reforming, at least about 90%, and in somecases at least about 95%, of the feedstock or pretreated feedstockoxygen content may be used to form CO and/or CO₂. It should also benoted, however, that, according to other embodiments, methanation of COand/or CO₂ to form methane will serve to reduce these amounts.

According to some embodiments, the desired balancing of biomass oxygenconversion to liquid and gaseous products may be achieved using moderatereaction conditions, such as moderate levels of pressure and/or hydrogenpartial pressure in the hydropyrolysis and/or hydroconversion reactors,as moderate levels of pressure and/or hydrogen partial pressure havebeen found to result in relatively greater yields of CO and CO₂, at theexpense of H₂O, compared to the use of higher levels of pressure and/orhydrogen partial pressure in conventional hydroprocessing operations(e.g., conventional hydrotreating and/or hydrocracking of petroleumfractions). Representative pressures and/or hydrogen partial pressuresin the hydropyrolysis and hydroconversion reactors (expressed as gaugepressures) may be independently less than about 55 barg (e.g., fromabout 7 barg to about 55 barg, from about 14 barg to about 41 barg, orfrom about 21 barg to about 38 barg).

According to some embodiments, it may be desirable for thehydropyrolysis reactor pressure to be substantially the same as that ofthe hydroconversion reactor, for example in the case in which thehydropyrolysis reactor vessel is operated at a pressure only slightlyabove that of the hydroconversion reactor vessel (e.g., at most about3.5 bar above, or at most about 2 bar above), as needed to at leastovercome the pressure differential between these vessels during normaloperation. Likewise, the pre-reactor vessel, if used, may be operated ata pressure only slightly above that of the hydropyrolysis reactor vessel(e.g., at most about 3.5 bar above, or at most about 2 bar above). Inthis manner, costs associated with the compression of gas streams,(e.g., recycled hydrogen-containing streams) may be reduced. Accordingto representative processes in which the pressure differential betweenreactors is minimized, the pre-reactor vessel may be disposed directlybelow the hydropyrolysis reactor vessel, or otherwise may form part ofthe hydropyrolysis reactor vessel (i.e., the solid bed material of thepre-reactor may be disposed in the same physical vessel as thehydropyrolysis reactor), in which case the operating pressures of thepre-reactor and hydropyrolysis reactor will be substantially the same.

Carbon dioxide that is generated from an integrated reforming step mayadvantageously be used to at least partially satisfy the inert gasrequirements of pretreating (in a pre-reactor vessel) as describedabove. According to particular embodiments, portions, for example afirst portion and/or a second portion, respectively, of the reformedcarbon dioxide may be introduced to (i) the pre-reactor vessel fordevolatilizing feedstock, (ii) operating one or more lock hoppers, (iii)blanketing of a flammable liquid, and/or (iv) drying feedstock. Portionsof carbon dioxide, when introduced to a pre-reactor vessel or feedstockdrying vessel, may be heated to temperatures effective to promote thedesired transformations of the biomass-containing feedstock associatedwith hydropyrolysis and/or pretreating (e.g., devolatilization), asdescribed herein.

Additional hydrogen that is generated from an integrated reforming stepmay advantageously be used to at least partially satisfy the hydrogenrequirements of pretreating (in a pre-reactor vessel) and/orhydropyrolysis (in a hydropyrolysis reactor vessel) as described above.According to particular embodiments, portions, for example a firstportion and/or a second portion, respectively, of the reformed hydrogenmay be introduced to (i) the hydropyrolysis reactor vessel forhydropyrolyzing the pre-reactor vapor stream or a portion thereof and/or(ii) the pre-reactor vessel. These portions, when introduced to therespective reactor vessels, may be heated to temperatures effective topromote the desired transformations of the biomass-containing feedstockassociated with hydropyrolysis and/or pretreating (e.g.,devolatilization), as described herein.

In the case of low quality initial feedstocks, such as MSW, containingrelatively high amounts (relative to the biomass contained in suchfeedstocks) of heteroatoms such as halogens (e.g., in the form ofchloride-containing compounds such as organic chlorides) as well asnitrogen (e.g., in the form of organic nitrogen-containing compounds)and sulfur (e.g., in the form of organic sulfur-containing compounds),the hydroconversion reactor output and the gaseous mixture that isrecovered from the hydroconversion reactor output, as described above,may contain contaminant gases including hydrogenation reaction productsof these heteroatoms, including detrimental amounts of HCl, H₂S, andNH₃, which may be problematic in terms of corrosion and safety concerns.Representative processes may therefore comprise removing at least aportion (e.g., all or substantially all) of one or more of thesecontaminant gases from the hydroconversion reactor output or the gaseousmixture. Such a removal may be accomplished, for example, by contactingat least a portion of the hydroconversion reactor output and/or thegaseous mixture with a solid sorbent such as CaCO₃ or other suitablemineral that has capacity for chloride removal (e.g., in the form ofHCl), as described above. According to other embodiments, thecontaminant gases may be effectively removed by contacting gas streams,including those described above, which contain acidic and/or basiccontaminant gases, with an appropriate liquid scrubbing solution (e.g.,a caustic solution, such as an NaOH solution, for the removal of acidiccontaminant gases).

FURTHER EMBODIMENTS

According to one representative embodiment, a process for producingliquid products from a biomass-containing feedstock such as MSW or algaemay comprise devolatilizing the feedstock in a pre-reactor vesselcontaining carbon dioxide and/or hydrogen and a solid bed material asdescribed above, to produce a pre-reactor vapor stream comprisingentrained solid particles. The process may further comprise separating,from the pre-reactor vapor stream, a solids-enriched stream and apurified pre-reactor vapor stream (i.e., a solids-depleted vapor stream,having a lower concentration of solids relative to that of thepre-reactor vapor stream). The purified pre-reactor vapor stream mayserve as the pretreated feedstock. In this case, such a pretreatedfeedstock is the portion of the pre-reactor process vapor stream that issubjected to hydropyrolyzing in a hydropyrolysis reactor vessel. Thehydropyrolysis reactor vessel may contain hydrogen and a second catalystor solid bed material (e.g., a deoxygenating catalyst), such that thehydropyrolyzing step produces a hydropyrolysis reactor output comprising(i) at least one non-condensable gas (e.g., H₂, CO₂, CO and/or one ormore low molecular weight hydrocarbon gas such as CH₄, C₂H₆, and/orC₂H₄), together with any stoichiometric excess of H₂ that is notconsumed in the hydropyrolysis reactor and remains after any water-gasshift reaction occurring in this reactor (ii) a partially deoxygenatedhydropyrolysis product (e.g., in the form of a condensable vapor), and(iii) char particles having an average particle size and/or averageparticle weight that is less than the average particle size and/oraverage particle weight, respectively, of char particles entrained inthe pre-reactor vapor stream. The process may comprise removing at leasta portion, and preferably substantially all, of the char particles fromthe hydropyrolysis reactor output to provide a purified hydropyrolysisreactor output (i.e., a solids-depleted hydropyrolysis reactor output,having a lower concentration of solids relative to that of thehydropyrolysis reactor output). The process may comprise hydroconvertingthe partially deoxygenated hydropyrolysis product in a hydroconversionreactor vessel, or otherwise in a hydroconversion zone comprising one ormore hydroconversion reactor vessels in series or parallel, using atleast one hydroconversion catalyst, as described above. Hydroconversionoccurs in the presence of at least a portion of the hydropyrolysisoutput components (i), (ii), and (iii) above that have not beenseparated (e.g., to remove entrained char particles), producing asubstantially fully deoxygenated hydrocarbon liquid product. Alsoproduced are non-condensable or low molecular weight gases, includingC₁-C₃ hydrocarbons (which may be paraffinic or olefinic), as well as anyCO and/or CO₂ that remains after any methanation reaction occurring inthe hydroconversion reactor vessel or zone, together with anystoichiometric excess of H₂ that is not consumed in the hydroconversionreactor vessel or zone and that remains after any water-gas shiftreaction occurring in this reactor or zone.

FIG. 1 depicts one possible, non-limiting, system 111 (the boundaries ofwhich are demarcated by a box) for carrying out the steps of phaseseparation, followed by steam reforming, followed by gas separation ofcarbon dioxide and hydrogen. As shown in FIG. 1, gaseous mixture 180 maybe conveyed to separation zone 190. Gaseous mixture 180 may compriseeffluent or output from a hydroconversion zone or a hydroconversionreactor (not shown in FIG. 1). Gaseous mixture 180 may include hydrogenand other non-condensable gases (e.g., CO, CO₂, and/or CH₄). Gaseousmixture 180 may be cooled using a hydroconversion zone outlet heatexchanger (not shown in FIG. 1), which may utilize an external heatexchange medium (e.g., cooling water), an exchange medium internal tothe integrated process (e.g., a feed stream), or a combination thereof.Cooling of hydroconversion zone effluent or output 180 (e.g., the outputfrom a single hydroconversion reactor, or otherwise two or more of suchreactors, as described below) allows for phase separation of thecomponents of this stream in separation zone 190.

Separation zone 190 may comprise one or more stages of phase separation,which may be achieved, for example, using one or more flash separatorsoperating in series, or otherwise using a packed column, and optionallya stripping medium (e.g., a flowing stripping gas), to achieve multipletheoretical equilibrium liquid-vapor separation stages. Due to thesignificant differences in relative volatility between components of thegaseous mixture and components of the substantially fully deoxygenatedhydrocarbon liquid, separation using a single flash separator or twoflash separators may be sufficient.

From separation zone 190, substantially fully deoxygenated hydrocarbonliquid 195 is recovered as a condensed fraction or liquid phase, andgaseous mixture 197 is removed as a non-condensed fraction or vaporphase. Substantially fully deoxygenated hydrocarbon liquid 195 may befractionated using further separation equipment (not shown), for examplea distillation column or series of distillation columns, to obtainsubstantially fully deoxygenated higher value liquid products such asgasoline boiling-range and/or diesel fuel boiling-range hydrocarbonfractions.

At least a portion of separated gaseous mixture 197 is introduced tosteam reformer 170, which provides a steam recycle stream 193, andgaseous mixture 171. Steam reformer 170 may be similar to steam reformer15 disclosed in U.S. Pat. No. 8,492,600. Gaseous mixture 171 compriseshydrogen and carbon dioxide. A net production of hydrogen from steamreformer 170 may be recycled to a hydropyrolysis reactor (not shown inFIG. 1) to satisfy some or all of the hydrogen requirements of thehydropyrolysis reactor. Gaseous mixture 171 from steam reformer 170 maybe enriched in hydrogen using gas separation apparatus 172. Gasseparation apparatus 172 may be any suitable apparatus configured toseparate hydrogen and carbon dioxide. Gas separation apparatus 172 maybe selected from the group consisting of a membrane separation unit, apressure swing adsorption (PSA) unit, a temperature swing adsorption(TSA) unit, an amine scrubber, and combinations thereof. Gas separationapparatus 172 may be configured to provide a high purityhydrogen-containing gas stream 198 for recycle to a hydropyrolysisreactor, and a high purity carbon dioxide-containing gas stream 173 forrecycle to one or more locations via carbon dioxide manifold 166, havinglines 161, 163, 164, and 167. Blowers or compressors (not shown inFIG. 1) may be configured to convey carbon dioxide from system 111through lines 161, 163, 164 and 167.

Line 161 may be configured to convey carbon dioxide from system 111 to adrying apparatus (e.g., drying apparatus 117 as depicted in FIG. 2, forexample using blower or compressor 133). Line 161 may be configured toconvey carbon dioxide to feedstock transfer screw 129 for operation offeedstock transfer screw 129, including blanketing. In an aspect,feedstock transfer screw 129 may be configured to supply feedstock 113to dryer 117. In an aspect, line 161 may be configured to convey carbondioxide to feed drum 131 to maintain pressure in feed drum 131 duringmaterial draw down. In an aspect, a separate line (not shown in FIG. 2)from system 111 may supply carbon dioxide to feedstock transfer screw129 and/or feed drum 131 that is different from line 161.

Line 163 may be configured to convey carbon dioxide to a lock hoppersystem (e.g., lock hopper system 115 as depicted in FIG. 2). Carbondioxide supplied from line 163 may be used to re-pressurize lock hopper119, including re-pressuring of high pressure recycle drum 121 and lowpressure recycle drum 123. Line 163 may be configured to supply carbondioxide directly to lock hopper 119 as shown in FIG. 2, and in anaspect, may be configured to supply carbon dioxide directly to highpressure recycle drum 121 and/or low pressure recycle drum 123.

Line 164 may be configured to convey carbon dioxide to a location orvessel (e.g., pre-reactor gas inlet 114 as depicted in FIG. 3 andfurther described below) wherein the carbon dioxide may be used ascarrier gas for another fluid. Line 167 may be configured to conveycarbon dioxide to a storage tank (e.g., storage tank 125 as depicted inFIG. 2) wherein the carbon dioxide may be used to blanket a flammablefluid (e.g., flammable fluid 127 as depicted in FIG. 2).

FIG. 2 depicts one possible, non-limiting, embodiment for carrying outhydropyrolysis of a biomass, which includes system 111 of FIG. 1.According to this particular embodiment, biomass-containing feedstock113 (e.g., MSW) may be introduced to a drying apparatus 117 where it maybe dried by carbon dioxide from line 161. After being dried in dryingapparatus 117, the feedstock may be conveyed to lock hopper subsystem115. Lock hopper subsystem 115 may comprise lock hopper 119, ahigh-pressure recycle drum 121, and a low-pressure recycle drum 123.Line 161 may be configured to convey carbon dioxide to drying apparatus117. Line 163 may be configured to convey carbon dioxide to a lockhopper subsystem 115. Line 164 may be configured to convey carbondioxide to a location or vessel (e.g., pre-reactor gas inlet 114 asdepicted in FIG. 3 and further described below) wherein the carbondioxide may be used as carrier gas for another fluid. Line 167 may beconfigured to convey carbon dioxide to storage tank 125 as shown in FIG.3, wherein the carbon dioxide may be used to blanket a flammable fluid127.

High-pressure recycle drum 121 may be configured to receive inert gasfrom lock hopper 119 at high pressure, which allows the lock hopperpressure to be lowered to a point where inert gas, e.g., carbon dioxide,can be transferred to low-pressure recycle drum 123. Low-pressurerecycle drum 123 may be configured to receive inert gas, e.g., carbondioxide, until the lock hopper pressure has fallen so far that directde-pressurization to atmosphere is called for, since the pressure inlow-pressure recycle drum 123 is, at that point, nearly equal to thepressure of lock hopper 119. During re-pressurization of lock hopper119, the lock hopper may be initially pressurized with recycled inertgas from low-pressure recycle drum 123, and may be subsequently raisedto a significantly higher pressure by the transfer of recycled inert gasfrom high-pressure recycle drum 121. Both the high and low-pressurerecycle drums may reduce the net need for inert gas associated withoperation of the plant, and may be handled as sources of inert CO₂ inthis simulation.

In an aspect, a stream comprising biomass may be conveyed to inlet 140,and from inlet 140 to hydropyrolysis reactor 150. Inlet 140 may receivethe biomass stream from lock hopper subsystem 115. High purityhydrogen-containing gas stream 198 may be conveyed from system 111 andintroduced as hydrogen-containing stream 144 into hydropyrolysis reactor150. Hydrogen feed blower or compressor 135 may be configured to conveycarbon dioxide from system 111 through line 198. Hydrogen-containingstream 144 may be introduced at the bottom of hydropyrolysis reactor150, as shown in FIG. 2, and may serve to entrain any solid particlespresent in the stream comprising biomass supplied by inlet 140.Hydrogen-containing stream 144 may be introduced at multiple axialheights of hydropyrolysis reactor 150 (corresponding to those withinand/or outside of, deoxygenating catalyst bed 146) for the purpose ofcontrolling temperature and/or localized gas velocities, or otherwiseimproving the uniformity of consumption of hydrogen.

Hydropyrolysis reactor 150 may therefore contain deoxygenating catalystbed 146, above which is expanded diameter gas-catalyst disengagementzone 148. Gas-catalyst disengagement zone 148 will generally extend to aheight above the transport disengagement height (TDH) for catalyst bed146 under the operating conditions employed in hydropyrolysis reactor150. Gas-catalyst disengagement zone 148 can provide a zone of reducedsuperficial gas velocity, promoting the effective disengagement ofrelatively small diameter catalyst particles that would otherwise beelutriated at the higher superficial gas velocity through bed 146.Optionally, gas-catalyst separation may be further improved usingmechanical separation devices such as cyclones (not shown) withingas-catalyst disengagement zone 148.

In addition, one or more deoxygenating catalyst inlets 152 and one ormore deoxygenating catalyst drawoff outlets 154 may provide forcontinuous or intermittent introduction and/or removal of deoxygenatingcatalyst (and any accompanying char) to and/or from hydropyrolysisreactor 150. For example, fresh deoxygenating catalyst may becontinuously or intermittently introduced through deoxygenating catalystinlet(s) 152 and spent or partially spent deoxygenating catalyst,together with any accompanying char, may be continuously orintermittently removed through deoxygenating catalyst drawoff outlet(s)154. Carbon dioxide may be conveyed from system 111, e.g., via line 163or line 164, to a subsystem similar to subsystem 115 shown in FIG. 2 tooperate a lock hopper associated with deoxygenating catalyst inlet 152.

According to the embodiment shown in FIG. 2, substantially all charparticles in hydropyrolysis reactor output 156 are removed inhydropyrolysis reactor gas-solids separator 158. Entrained charparticles may be removed using mechanical devices including filters,external cyclones, electrostatic separators, liquid contactors (e.g.,bubblers), etc. to provide purified hydropyrolysis vapor stream 160having a reduced char content and optionally a char-enriched stream 162,for example in the case of external cyclones, electrostatic separators,and other mechanical devices that provide an effluent stream ofrelatively concentrated char particles.

Optional char-enriched stream 162 may be conveyed to char drum 137. Inan aspect, carbon dioxide may be conveyed from system 111, e.g., vialine 163 or line 164, to a subsystem similar to subsystem 115 shown inFIG. 2 to operate a lock hopper corresponding to char drum 137 and/or tore-pressurize char drum 137.

FIG. 3 is a schematic flow diagram of an alternative embodiment,including the system 111 of FIG. 1, a pre-reactor, and a hydropyrolysisreactor. This embodiment is effective for carrying out the steps ofpretreatment of a biomass-containing feedstock, followed byhydropyrolysis of a pre-reactor vapor stream that is generated from thepretreatment. According to this particular embodiment,biomass-containing feedstock (e.g., MSW) is introduced to a lowersection (e.g., the bottom) of pre-reactor 120 through feedstock inlet112 after being combined with a pre-reactor gas, introduced topre-reactor 120 through pre-reactor gas inlet 114. The feedstock and thepre-reactor gas may be introduced to pre-reactor 120 at the same ordifferent locations, for example within particle bed 116. Both thefeedstock and the pre-reactor gas may, independently, also be introducedat multiple locations. For example, the pre-reactor gas may beintroduced at multiple axial heights of pre-reactor 120 (correspondingto those within and/or outside of, particle bed 116) for the purpose ofcontrolling temperature and/or localized gas velocities, or otherwiseimproving the uniformity of consumption of reactant gases (e.g.,hydrogen). Feedstock inlet 112 may receive feedstock 113 from asubsystem similar to subsystem 115 previously described with respect toFIG. 1.

Pre-reactor gas may comprise carbon dioxide and/or hydrogen, either orboth of which may be supplied from system 111. Pre-reactor gas may havea sufficient superficial velocity, within pre-reactor 120, for thefluidization of some or all of the solid particles of a particle bed 116contained in this reactor. Particle bed 116 generally includes particlesof biomass-containing feedstock introduced through feedstock inlet 112,as well as a solid bed material that may be charged to pre-reactor 120initially and retained in this reactor due to the gas-solid separationoccurring at particle bed interface 118, for example if the pre-reactorgas within pre-reactor 120 fluidizes particle bed 116 but hasinsufficient superficial velocity for the entrainment (elutriation) ofthe solid bed material. Particle bed interface 118 may thereforerepresent an upper boundary of an expanded or a quiescent, dense bedphase, or otherwise an upper boundary of a fixed bed. To ensure acomplete or substantially complete separation of solid bed material frompre-reactor vapor stream 136 exiting pre-reactor 120, anexpanded-diameter gas-solids disengagement zone 124 may be included inan upper section (e.g., freeboard region) of this reactor, aboveparticle bed interface 118. Gas-solids disengagement zone 124 willgenerally extend to a height above the transport disengagement height(TDH) for particles of solid bed material under the operating conditionsemployed in pre-reactor 120. Gas-solids disengagement zone 124 canprovide a zone of reduced superficial gas velocity, promoting theeffective disengagement of relatively small diameter solid particlesthat would otherwise be elutriated at the higher superficial gasvelocity through particle bed 116. Optionally, gas-solid separation maybe further improved using mechanical separation devices such as cyclones(not shown) within gas-solids disengagement zone 124. Such gas-solidseparation, in gas-solids disengagement zone 124, is normally effectivefor providing pre-reactor vapor stream 136 having very little, if any,(e.g., less than about 0.1% by weight) of solid bed material, althoughin many cases this gas-solids separation is not effective for removingchar, which is typically of a smaller particle size and more difficultto remove than solid bed material, from this vapor stream. Often, it isdesirable to feed this char to downstream hydropyrolysis reactor 150,although steps, described herein, can also be taken to remove this char.

Both the biomass-containing feedstock and the solid bed material may beintroduced to pre-reactor 120 using suitable mechanical equipment formoving solid particles, such as an auger or a screw extruder. A fastmoving stream of carrier gas (e.g., an inert gas having a superficialvelocity of greater than about 5 m/sec), may be used alone or incombination with the pre-reactor gas, in order to aid the introductionof the biomass-containing feedstock and/or solid bed material intopre-reactor 120. As described above, a slow-moving (or low superficialvelocity) stream of inert gas, such as a CO₂ product described herein,may be sent down a solids transfer screw in order to provide thermalmanagement (heating or cooling) of the screw and material in it, and/orthe localized region in a fluidized bed at which that screw terminates.A slow-moving stream of gas may also be used as a sweep gas, whichprevents the hydropyrolysis process (e.g., reactor) atmosphere, andprocess vapors, from diffusing or otherwise moving upstream along thescrew. If these process vapors do come in contact withbiomass-containing feedstock or other particulate solids inside thescrew, they may interfere with the operation of the screw.

As described previously, the solid bed material in pre-reactor 120 mayact as a catalyst, a sorbent, a heat transfer medium, or provide somecombination of these functions. In particular embodiments, this materialmay be introduced continuously or intermittently to pre-reactor 120through bed material inlet 132 to compensate for any losses, for exampledue to attrition. Otherwise, solid bed material may be introduced tocompensate for losses accompanying the purposeful removal of solids fromparticle bed 116. As described above, solids may be removed from one ormore solids drawoff outlets 134 corresponding to one or more axialheights within solid particle bed 116, at which solid biomass-containingfeedstock (e.g., representing at least a portion of the solid particlesin particle bed 116) having either an undesired characteristic, orotherwise an improved characteristic, relative to the initial feedstock(e.g., introduced through feedstock inlet 112), is enriched.

According to one representative embodiment, biomass-containing feedstockis selectively removed from particle bed 116 at an axial height at whichparticles of feedstock that are relatively inert in the environment ofpre-reactor 120 are enriched. For example, particles of feedstock mayaccumulate in particle bed 116 if their composition does not allowsufficient devolatilization and subsequent elutriation from pre-reactor120. Such particles may include particles of glass, metal, or plasticthat, without the use of a solids drawoff outlet 134, would remain inpre-reactor 120 indefinitely, account for an increasing proportion ofparticle bed 116, and eventually disrupt the intended operation ofpre-reactor 120.

In the case of removal of biomass-containing feedstock enriched in anundesired characteristic, such as a high ash content or a highnon-biological material content, the feedstock remaining in pre-reactor120 necessarily has an improved characteristic, i.e., a reduced ashcontent, over the initial feedstock. Therefore, this removal results ina pretreating step as defined herein, which is carried out in situ inpre-reactor 120, whereby the feedstock remaining in particle bed 116 isa pretreated feedstock, in addition to pre-reactor vapor stream 136exiting pre-reactor 120. According to this embodiment, both apre-treating step and a devolatilizing step, as defined herein, may becarried out simultaneously in pre-reactor 120. The feedstock removedthrough a solids drawoff outlet 134, enriched in an undesiredcharacteristic, may be sent for recovery/reclamation of non-biologicalmaterials (e.g., plastics) or may otherwise be used in furtherprocessing steps (e.g., hydropyrolysis), albeit in a different mannerfrom the manner in which the pretreated feedstock is used. For example,the removed feedstock may be fed to the hydropyrolysis reactor vessel ata different location (e.g., a different axial height), at a differenttemperature, and/or through different equipment (e.g., a screwextruder), relative to the pretreated feedstock. As another example ofboth a pre-treating step and a devolatilizing step being carried outsimultaneously in pre-reactor 120, the solid bed material may havesorptive capacity for corrosive species such as chloride that might, inthe absence of such solid bed material, otherwise exit pre-reactor 120in pre-reactor vapor stream 136 (e.g., in the form of HCl). In thiscase, pre-reactor vapor stream 136, including entrained solid particles,is a pretreated feedstock having an improved characteristic, in terms ofreduced corrosive species content, over the initial feedstock introducedthrough feedstock inlet 112.

Any use of the feedstock removed from pre-reactor 120, either having animproved characteristic or otherwise being enriched in an undesiredcharacteristic, and whether or not further processed in an integratedprocess as described herein, may be preceded by its separation (e.g., bysize or density) from some or all of the solid bed material. Any solidbed material separated in this manner may be returned to pre-reactor120, for example through bed material inlet 132.

In the case of removal of feedstock enriched in a desired characteristic(e.g., having one or more of the improved characteristics as describedabove), such as having a more uniform particle size, this removalresults in a pretreating step as defined herein, in which the removedfeedstock has an improved characteristic, rendering it more easilyupgradable in further processing steps (e.g., hydropyrolysis), forexample following its separation (e.g., by size or density) from some orall of the solid bed material. Any solid bed material separated in thismanner may be returned to pre-reactor 120, for example through bedmaterial inlet 132.

In view of the foregoing description, fluidization of particle bed 116may advantageously serve to classify the initial feedstock, introducedthrough feedstock inlet 112, according to a number of possiblecharacteristics described herein, and particularly those characteristicsrelating to fluid dynamic properties, namely reduced average particlesize, reduced average particle aerodynamic diameter, increased averageparticle surface area to mass ratio, and a more uniform particle size.According to another representative embodiment, a fraction of thefeedstock within pre-reactor 120 may not be fluidized at all, under agiven set of conditions. Such a fraction may therefore be removedthrough a solids drawoff outlet 134 positioned at or near the bottom ofparticle bed 116, with the removed feedstock having a reduced averageparticle surface area to mass ratio (e.g., being enriched in glass ordense metallic particles contained in the feedstock), thereby resultingin an in situ pretreating step as defined herein, in which thepretreated feedstock remaining in particle bed 116 has the improvedcharacteristic of an increased average particle surface area to massratio. According to further embodiments, the superficial gas velocity inpre-reactor 120 may be varied (e.g., by varying the cross-sectional areawithin particle bed 116) in order to segregate/concentrate solidparticles having certain fluid dynamic properties at differing axialheights within pre-reactor 120.

Depending on the gas introduced through pre-reactor gas inlet 114, theconditions used in pre-reactor 120, and the positioning of solidsdrawoff outlet(s) 134 a suitable pretreating step may be performed inpre-reactor 120, optionally in combination with a devolatilizing step.As is apparent from the foregoing description, if both pretreating anddevolatilizing steps are carried out, they may be performed on all ofthe feedstock introduced to pre-reactor 120, or otherwise on differentfractions of this feedstock that are either removed from particle bed116 or retained in this particle bed until sufficientlydevolatilized/pyrolyzed and elutriated from pre-reactor 120.

Devolatilization and optional pyrolysis (e.g., hydropyrolysis) of thefeedstock, when carried out in pre-reactor 120, require elevatedtemperatures. In many cases, therefore, it may be desirable for anysolid bed material, introduced either continuously (e.g., followingregeneration as described in greater detail below) or intermittentlythrough bed material inlet 132, to act as a convenient heat transfermedium that transfers sufficient heat to pre-reactor 120 fordevolatilization and optional pyrolysis of the feedstock. This functionof transferring heat may be combined with other functions of the solidbed material, described above, including catalytic and/or sorptivefunctions. Heat may be transferred into the pre-reactor using thepre-reactor gas and the biomass-containing feedstock, as an alternativeto, or in combination with, the solid bed material. Any of thebiomass-containing feedstock, solid bed material, pre-reactor gas, orany combination thereof, may be heated prior to entry to pre-reactor120.

In addition to functioning as a heat transfer medium, the solid bedmaterial may exhibit catalytic activity, such as hydro conversion (e.g.,hydrotreating) catalytic activity as described above, to facilitate atleast some conversion of the products of devolatilization and/orpyrolysis to intermediates (which can be further reacted in downstreamoperations), or even to desired end products. The catalytic activity mayfacilitate the conversion of gaseous products of devolatilization and/orpyrolysis to a desired composition, for example in terms of amounts ofnon-condensable gases including H₂, CO₂, CO, and CH₄, as well as theamounts and types of condensable gases such as aromatic, oxygenatedhydrocarbons (e.g., phenols and cresols). Representative solid bedmaterials may have one or more specific catalytic activities thatinclude deoxygenation activity, cracking activity, water-gas shiftactivity, methanation activity, and combinations thereof. Those skilledin the relevant art, consulting the present disclosure, are apprised ofsuitable, active catalyst metals (e.g., Co, Mo, Ni, V, W, Pd, Pt, Rh)and suitable catalyst support materials (e.g., amorphous or crystallinemetal oxides such as silica and alumina, zeolites such as MFI-typezeolites including ZSM-5, and non-zeolitic molecular sieves such asSAPO-type materials) for imparting one or more, desired catalyticactivities to the solid bed material, for use in the environment ofpre-reactor 120.

According to some embodiments, the catalytic activity of at least someof the solid bed material may desirably be the same type and degree asused in a downstream hydropyrolysis reactor. In other embodiments, thesame type of catalytic activity may be desired, but at a differentdegree (level) of activity. In such embodiments, solid bed materials, inthis case catalysts, for the pre-reactor and hydropyrolysis reactor mayinclude the same types of materials, but with different amounts ofactive, deposited catalyst metals on a support material. Alternatively,a catalyst in fresh condition may be used in the hydropyrolysis reactor,if greater catalytic activity is desired in its operation, whereas thesame catalyst in a partially spent (e.g., partially coked) condition maybe used in the pre-reactor if reduced catalytic activity is desired inits operation. Conveniently, therefore, catalyst may be continuously orintermittently removed from the hydropyrolysis reactor (e.g., afterattaining a specified coke level or reduction in activity) andcontinuously or intermittently introduced to the pre-reactor. In analternative embodiment, if higher catalytic activity is desired in thepre-reactor relative to the hydropyrolysis reactor, fresh catalyst maybe used in the former and continuously or intermittently transferred tothe latter.

Following disengagement of bed material and un-elutriated char particlesin gas-solids disengagement zone 124 of pre-reactor 120, pre-reactorvapor stream 136 may be withdrawn from pre-reactor 120. Pre-reactorvapor stream 136 will generally comprise entrained or elutriated solidparticles of char, optionally in combination with particles (e.g.,attrited fine particles) of the solid bed material. Fluidizationconditions can be controlled within pre-reactor 120 to establish a givenchar and/or solid bed material cutoff diameter, above which the charand/or solid bed material is returned to, or retained in, particle bed116 and below which the char and/or solid bed material is removed frompre-reactor 120 in vapor stream 136. In this manner, the residence timeof the solid feedstock particles can be controlled, insofar as thefeedstock is prohibited from exiting pre-reactor 120 until it isdevolatilized/pyrolyzed to a desired extent, corresponding to a cutoffdiameter. Due to potentially different densities and surface geometriesof the char and solid bed material, the cutoff diameters for the charand solid bed material may be different and selected to accomplishdifferent objectives. As noted above, mechanical equipment such ascyclones may, in combination with the fluidization conditions (e.g.,superficial gas velocity) influence the cutoff diameters. Control ofchar residence time, together with the control of other conditions inpre-reactor 120, including, for example, temperature, total pressure,and/or hydrogen partial pressure, may promote the devolatilization,pyrolysis, and/or hydropyrolysis of biomass-containing feedstock underparticle fluidizing conditions in a manner tailored to the initialcharacteristics of the feedstock and desired characteristics of thepre-reactor vapor and/or any feedstock withdrawn from particle bed 116.

In addition to entrained char particles, pre-reactor vapor stream 136exiting pre-reactor 120 generally contains the gaseous products formedfrom devolatilization, and possibly also formed from a desired extent ofpyrolysis. Such gaseous products can include CO, CO₂, H₂O, hydrocarbons,and oxygenated hydrocarbons. Condensable vapors other than water vapor,such as condensable hydrocarbons and oxygenated hydrocarbons, constitutea deoxygenated product of devolatilization. Under certain operatingconditions of pre-reactor 120, for example in the case of introductionof hydrogen through pre-reactor gas inlet 114 or as a separate stream,together with the use of a solid bed material having catalyticmethanation activity (and potentially water-gas shift activity), COand/or CO₂ may be substantially or completely converted to CH₄, in whichcase CO and/or CO₂ may be substantially or completely absent frompre-reactor vapor stream 136. In a highly methanating environment, itmay be possible for pre-reactor vapor stream 136 to comprise less than 5vol-% or even less than 1 vol-% of combined CO and CO₂, based on theamount of all non-condensable gases in this stream.

According to the embodiment of FIG. 3, pre-reactor vapor stream 136 isfed to optional pre-reactor gas-solids separator 138, for the removal ofentrained solids such as char and/or fine particles of solid bedmaterial. Entrained solids may be removed using mechanical devicesincluding filters, external cyclones, electrostatic separators, liquidcontactors (e.g., bubblers), etc. If pre-reactor gas-solids separator138 is used, a purified pre-reactor vapor stream is obtained andsupplied to inlet 140 having a reduced content of solids relative topre-reactor vapor stream 136. Depending on the particular method forseparating the solids, a solids-enriched stream 142 may also beobtained, having an increased content of solids relative to pre-reactorvapor stream 136. For example, external cyclones, electrostaticseparators, and other mechanical devices can provide a continuoussolids-enriched stream 142 of relatively concentrated solid particles.In general, the solid particles in solids-enriched stream 142 will havea higher average particle size and/or higher average particle weight,compared to any solid particles remaining in the purified pre-reactorvapor stream conveyed to inlet 140. If gas-solids separator 138 is used,a portion of pre-reactor vapor stream 136, namely the purifiedpre-reactor vapor stream conveyed to inlet 140 may be introduced tohydropyrolysis reactor 150. If a gas-solids separator is not used, thenthe entire pre-reactor vapor stream 136, including solids entrained frompre-reactor 120, may be introduced to hydropyrolysis reactor 150.

In addition to all or a portion of pre-reactor vapor stream 136,hydrogen-containing stream 144 may also be introduced to hydropyrolysisreactor 150. Hydrogen-containing stream 144 may be introduced at thebottom of hydropyrolysis reactor 150, as shown in FIG. 3, and may serveto entrain any solid particles present in pre-reactor vapor stream 136or purified pre-reactor vapor stream 140. Hydrogen-containing stream 144may be introduced at multiple axial heights of hydropyrolysis reactor150 (corresponding to those within and/or outside of, deoxygenatingcatalyst bed 146) for the purpose of controlling temperature and/orlocalized gas velocities, or otherwise improving the uniformity ofconsumption hydrogen.

Hydropyrolysis reactor 150 may therefore contain deoxygenating catalystbed 146, above which is expanded diameter gas-catalyst disengagementzone 148, functioning similarly to gas-solids disengagement zone 124 ofpre-reactor 120. In addition, one or more deoxygenating catalyst inlets152 and one or more deoxygenating catalyst drawoff outlets 154 mayprovide for continuous or intermittent introduction and/or removal ofdeoxygenating catalyst to and/or from hydropyrolysis reactor 150. Forexample, fresh deoxygenating catalyst may be continuously orintermittently introduced through deoxygenating catalyst inlet(s) 152and spent or partially spent deoxygenating catalyst may be continuouslyor intermittently removed through deoxygenating catalyst drawoffoutlet(s) 154, together with any accompanying char. According to aparticular type of operation described above, the removed catalyst maybe transferred to bed material inlet 132 of pre-reactor 120 to providesolid bed material in the form of partially spent catalyst.

At least a portion of pre-reactor vapor stream 136 (e.g., purifiedpre-reactor vapor stream 140) may be subjected to a hydropyrolyzing stepin hydropyrolysis reactor 150 in the presence of hydrogen and thedeoxygenating catalyst. A hydropyrolysis reactor output 156, containingone or more non-condensable gases, an aqueous hydropyrolysis product, apartially deoxygenated hydropyrolysis product, and char particlesproduced in hydropyrolysis reactor vessel 150 is removed. As describedabove with respect to pre-reactor vapor stream 136, non-condensablegases in hydropyrolysis reactor output 156 can include H₂, CO₂, CO, CH₄,and mixtures thereof, with the relative proportions depending on, forexample, the methanating activity and water-gas shift activity of thedeoxygenating catalyst. In the case of a deoxygenating catalyst withsubstantial methanation activity, CO₂ and/or CO may be substantiallyabsent from hydropyrolysis reactor output 156. For example, it may bepossible for hydropyrolysis reactor output 156 to comprise less than 5vol-% or even less than 1 vol-% of combined CO and CO₂, based on theamount of all non-condensable gases present.

According to the embodiment shown in FIG. 3, substantially all charparticles in hydropyrolysis reactor output 156 are removed inhydropyrolysis reactor gas-solids separator 158. Entrained charparticles may be removed using mechanical devices including filters,external cyclones, electrostatic separators, liquid contactors (e.g.,bubblers), etc. to provide purified hydropyrolysis vapor stream 160having a reduced char content and optionally a char-enriched stream 162,for example in the case of external cyclones, electrostatic separators,and other mechanical devices that provide an effluent stream ofrelatively concentrated char particles.

FIG. 4 depicts a non-limiting alternative embodiment, including system111 of FIG. 1, in which pre-reactor 220 and hydropyrolysis reactor 250are in a stacked relationship. This configuration may be advantageous incertain cases, for example if operating conditions (e.g., temperaturesand/or pressures) in these reactors 220, 250 are the same or similar.Otherwise, this configuration may be employed in embodiments in whichthere is no external separation of solid particles (for example usingpre-reactor gas-solids separator shown in FIG. 3) entrained inpre-reactor vapor 236, entering hydropyrolysis reactor 250. Using thisconfiguration, part or all of the gas requirements, including thehydrogen requirements, for both hydropyrolysis reactor 250 andoptionally pre-reactor 220, may be provided through pre-reactor gasinlet 214. However, part or all of these gas requirements mayalternatively be provided through a combination of pre-reactor gas inlet214 and hydrogen containing stream 244, optionally in combination withother gas inlets (not shown).

The separation of deoxygenating catalyst bed 246 in hydropyrolysisreactor 250 from particle bed 216 in pre-reactor 220 may be aided tosome extent by upwardly flowing pre-reactor vapor 236, and in thisregard the superficial velocity of this vapor may be increased as itenters hydropyrolysis reactor 250, for example by passing this vaporthrough constricted opening 275 at the base of hydropyrolysis reactor250. Constricted opening 275 will generally have a cross-sectional areathat is less than the cross-sectional area of pre-reactor 220, or atleast less than the cross-sectional area of gas-solids disengagementzone 224 of pre-reactor 220. Constricted opening 275 may be covered byone or more mechanical separation elements, such as a screen, mesh,inert material, etc. to maintain deoxygenating catalyst bed 246 withinhydropyrolysis reactor 250. For example, constricted opening 275 may becovered by a screen having openings of a suitable size or diameter,which allow elutriated solid particles in pre-reactor vapor 236 to passinto hydropyrolysis reactor 250, but do not allow deoxygenating catalystto pass into pre-reactor 220.

As is apparent from the foregoing description of the embodiment depictedin FIG. 4, pre-reactor 220 and hydropyrolysis reactor 250 may togethercomprise a single vessel. As in the embodiment depicted in FIG. 3,pre-reactor 220 and hydropyrolysis reactor 250 can include,respectively, gas-solids disengagement zone 224 and gas-catalystdisengagement zone 248, extending to sufficient heights above particlebed 216 and deoxygenating catalyst bed 246, respectively, for effectivedisengagement of solid bed material from the pre-reactor vapor 236 anddeoxygenating catalyst from hydropyrolysis reactor output 256. Theefficiency or degree of this disengagement may be improved usingmechanical separation devices such as cyclones (not shown) withingas-solids disengagement zone 224 and/or gas-catalyst disengagement zone248. The effective disengagement occurring within disengagement zones224, 248, whether or not mechanical separation devices are used, doesnot preclude the existence of minor amounts of solid bed material inpre-reactor vapor 236 and/or minor amounts of deoxygenating catalyst inhydropyrolysis reactor output 256, with these minor amounts comprisingfine solid particles resulting from, for example, mechanical breakagedue to attrition. Such fine solid particles, as well as entrained charparticles, may be removed in further separation steps, for example usinghydropyrolysis reactor gas-solids separator 258 to yield purifiedhydropyrolysis vapor stream 260 and optionally char-enriched stream 262(which may also be enriched, relative to hydropyrolysis reactor output256, in other solids such as catalyst and/or other solid bed material,in addition to char). Gas-solids separator 258 can include any device asdescribed with respect to the embodiment depicted in FIG. 3 for theremoval of entrained char particles, and/or other solids, exiting thehydropyrolysis reactor.

Other features described with respect to the embodiment depicted in FIG.3 function in the same or in an analogous manner in the embodimentdepicted in FIG. 4. These features include feedstock inlet 212,pre-reactor gas inlet 214, hydrogen-containing stream 244, bed materialinlet 232 and deoxygenating catalyst inlet 252. These features alsoinclude solids drawoff outlet(s) 234, char-enriched stream 262, anddeoxygenating catalyst drawoff outlet 254. The introduction of solids(e.g., feedstock, solid bed material, and/or catalyst) to thepre-reactor 120, 220 or hydropyrolysis reactor 150, 250 may beaccomplished using suitable mechanical equipment for moving solidparticles, such as an auger or a screw extruder. A fast-moving (or highsuperficial velocity) stream of carrier gas (e.g., an inert gascomprising a CO₂ product as described herein and having a superficialvelocity of greater than about 5 m/sec), may be used alone or incombination with process gas streams described herein, in order to aidthe introduction of the solids. Alternatively, a slow-moving (or lowsuperficial velocity) stream of inert gas may be used to provide thermalmanagement (heating or cooling) of the solids transport equipment (e.g.,solids transfer screw).

Likewise, the withdrawal of solids (e.g., feedstock enriched in ashcontent or having some other undesirable characteristic) from thepre-reactor 120, 220 or hydropyrolysis reactor 150, 250 may beaccomplished using similar equipment, such as a solids-removal screw, orotherwise using an overflow pipe, sequentially cycled lock hoppers, orother known equipment. According to one particular embodiment, solidswithdrawn from solids drawoff outlet(s) 134, 234 of pre-reactor 120, 220may include solid bed material having catalytic hydrotreating activity,as described above. This activity decreases over time as impurities suchas carbon (coke), melted plastic, and other reaction products orfeedstock impurities deposit on the solid bed material. Solid bedmaterial that is a hydrotreating catalyst, following removal from solidsdrawoff outlet(s) 134, 234, may therefore be subjected to a suitableregeneration, by combusting the accumulated coke and other impuritieswith oxygen to yield a regenerated solid bed material that may bereturned to pre-reactor 120, 220 (e.g., through bed material inlet 132,232) or even introduced to hydropyrolysis reactor 150, 250 (e.g.,through deoxygenating catalyst inlet 152, 252. Prior to any suchregeneration and re-use of the regenerated catalyst, it may be desirableto separate the removed solid bed material (e.g., spent hydrotreatingcatalyst) from other solids (e.g., char particles generated from thefeedstock and/or inert materials contained in the feedstock) containedin particle bed 116, 216 at the location (e.g., axial height ofpre-reactor 120, 220) at which the solid bed material is removed. In asimilar manner, deoxygenating catalyst withdrawn from deoxygenatingcatalyst bed 146, 246 of hydropyrolysis reactor 150, 250, may also beregenerated, optionally following a separation from other solids (e.g.,char particles) contained in deoxygenating catalyst bed 146, 246 at thelocation (e.g., axial height of hydropyrolysis reactor 150, 250) atwhich the deoxygenating catalyst is removed.

Advantageously, the fluidized bed regeneration of withdrawn solid bedmaterial from pre-reactor 120, 220 or withdrawn deoxygenating catalystfrom hydropyrolysis reactor 150, 250, to at least partially restorehydrotreating activity, can simultaneously act to classify varioussolids, in a similar manner as described above with respect to theoperation of pre-reactor 120, 220. That is, solids having distinct fluiddynamic properties can, under appropriate conditions of fluidization(e.g., superficial gas velocity), segregate/concentrate at differingaxial heights within a fluidized bed regeneration vessel, where they maybe withdrawn to achieve a desired separation. For example, in the caseof solid bed material withdrawn from pre-reactor 120, 220, particleshaving a relatively low surface area to mass ratio (e.g., metals, glass,and/or other inert materials), which are more difficult to fluidize (ormay not be fluidized at all) may tend to concentrate near (or at) thebottom of a fluidized bed. According to other exemplary separationsbased on fluid dynamic properties, ash (in the form of decarbonizedchar) may be withdrawn from an upper section or the top of a fluidizedbed regeneration vessel (e.g., as particles elutriated in the exitinggas stream, such as a combustion (flue) gas effluent). Regeneratedcatalyst, having a reduced coke content, may be withdrawn from a centralsection of a fluidized bed regenerator vessel (e.g., from within thefluidized particle bed) and returned to pre-reactor 120, 220 and/orutilized in hydropyrolysis reactor 150, 250. According to otherembodiments, the superficial gas velocity in a fluidized bed regeneratorvessel may be varied (e.g., by varying the cross-sectional area withinthe fluidized bed) in order to segregate/concentrate solid particleshaving certain fluid dynamic properties at differing axial heightswithin the regenerator vessel.

Some hydrotreating catalysts, and particularly those having Co, Ni,and/or Mo as catalytic metals (e.g., CoMo and NiMo catalysts) requirethese metals to exist in their sulfided (or oxidized) state in order toremain catalytically active. Specifically, if sulfided catalysts are notexposed to sufficient sulfur (e.g., as H₂S) during their normal use,they may become deactivated over time due to a loss of sulfided metalsites. Consequently, solid bed material withdrawn from pre-reactor 120,220 or deoxygenating catalyst withdrawn from hydropyrolysis reactor 150,250 may be subjected to fluidized bed sulfiding, with the sameadvantages, in terms of classifying solid particles with differing fluiddynamic properties, as described above with respect to fluidized bedregeneration. Therefore, the exemplary separations described above,based on differing fluid dynamic properties of particles, are applicableto both fluidized bed sulfiding and fluidized bed regeneration.Accordingly, in the case of separating elutriated, fine solids ingaseous effluent streams, these solids may be removed in either acombustion (flue) gas effluent of a regeneration vessel or ahydrogen-containing sulfiding effluent of a sulfiding vessel.

Unlike catalyst regeneration that involves the combustion of depositedcoke in an oxidizing environment, suitable catalyst sulfiding isperformed under reducing conditions. A preferred fluidizing gas forsulfiding solid bed material or deoxygenating catalyst is apredominantly hydrogen-containing gas having a minor amount of hydrogensulfide (H₂S) or precursor compound that forms H₂S under sulfidingconditions. For example, the fluidizing gas may comprise at least 50mole-% H₂ (e.g., from about 50 mole-% to about 99 mole-%) and less thanabout 3 mole-% H₂S (e.g., from about 250 mole-ppm to about 3 mole-%, andmore typically from about 1000 mole-ppm to about 1 mole-%). The use ofsuch a hydrogen-containing fluidizing gas at elevated temperature can,in addition to sulfiding withdrawn catalyst, also promotehydrogasification of coke deposited on the catalyst, as well ashydrogasification of any char that may be carried into a fluidized bedsulfiding vessel. Hydrogasification can advantageously remove cokedeposits from solid bed material or deoxygenating catalyst, which canhelp restore catalytic activity or other functions (e.g., adsorptivecapacity). In addition, hydrogasification of coke and char can be usedto form methane and other light hydrocarbons in the gaseous effluentfrom a fluidized bed sulfiding vessel. In a particular embodiment, asuitable methanation catalyst (e.g., a supported nickel catalyst) may beused to facilitate the production of methane under hydrogasificationconditions, or otherwise in a separate reaction step performed (e.g., ina methanation reactor) on the gaseous effluent from the fluidized bedsulfiding vessel.

FIG. 5 depicts an embodiment of an integrated hydropyrolysis processincorporating system 510, which includes a hydropyrolysis reactor and anoptional pre-reactor, as separate vessels with intervening process linesand equipment as described with respect to FIG. 3, or in a stackedrelationship as described with respect to FIG. 4. The embodiment of FIG.5 further incorporates system 111 of FIG. 1. Accordingly, inputs tosystem 510 include feedstock inlet 312 for the introduction ofbiomass-containing feedstock (e.g., MSW), as well as pre-reactor gasinlet 314 and hydrogen containing stream 344 (if used) for theintroduction of gaseous feeds to the pre-reactor and the hydropyrolysisreactor, respectively. Optional inputs include bed material inlet 332and deoxygenating catalyst inlet 352. Optional outputs from system 510include solids-enriched stream 342, as well as solids drawoff outlet(s)334, char-enriched stream 362, and deoxygenating catalyst drawoff outlet354.

As shown in FIG. 5, purified hydropyrolysis vapor stream 360, followingthe removal of substantially all char particles from the hydropyrolysisreactor output, is sent for further processing. As described above,purified hydropyrolysis vapor stream 360 generally comprises at leastone non-condensable gas (e.g., H₂, CO, CO₂, and/or CH₄), water vapor,and other condensable vapors comprising a partially deoxygenatedhydropyrolysis product. The temperature of purified hydropyrolysis vaporstream 360 may be adjusted (heated or cooled) as needed, for exampleusing hydroconversion zone inlet heat exchanger 365, to obtain desiredconditions in hydroconversion zone 375. Hydroconversion zone inlet heatexchanger 365 may utilize an external heat exchange medium (e.g.,cooling water or high pressure steam), an exchange medium internal tothe integrated process (e.g., a feed stream), or a combination thereof.Hydroconversion zone 375 may comprise one or more hydroconversionreactor vessels. According to one embodiment, a single hydroconversionreactor vessel is used in hydroconversion zone 375. The reactor vesselmay contain a single type of hydroconversion catalyst for converting, byfurther deoxygenation, the partially deoxygenated hydropyrolysis productto a substantially fully deoxygenated hydrocarbon product, which mayultimately be condensed to provide a substantially fully deoxygenatedhydrocarbon liquid having properties as described above.

Catalysts suitable for use in hydroconversion zone 375 include thosehaving hydrotreating activity, as described above, to promote thedesired hydrodeoxygenation, decarbonylation, and decarboxylationreactions, the proportions of which may be controlled according to theparticular operating conditions (e.g., pressure or hydrogen partialpressure) used in hydroconversion zone 375, including the one or morehydroconversion reactor vessels. Such catalysts may also be used topromote hydrodentrification, hydrodesulfurization, and/orhydrodechlorination, as necessary to remove heteroatoms from thepartially deoxygentated hydropyrolysis product, in the form of the gasesNH₃, H₂S, and/or HCl, which may be removed from the fully deoxygenatedhydrocarbon liquid by downstream phase separation of a gaseous mixturetherefrom. The need for the removal of heteroatoms is largely dependenton the properties of the particular biomass-containing feedstock beingprocessed, including the contents of these heteroatoms.

According to some embodiments, a single hydroconversion reactor vesselis used in hydroconversion zone 375, having catalysts with hydrotreatingactivity and optionally other hydroprocessing activities as describedabove (e.g., hydrocracking and/or hydroisomerization activities). Thediffering activities can be provided with a single catalyst (e.g., acatalyst having hydrotreating activity in addition to hydrocrackingactivity by virtue of the introduction of acid sites on the supportmaterial). Otherwise, the differing activities can be provided withmultiple catalysts, having differing hydroprocessing activities asdescribed above, positioned in discreet catalyst beds within thehydroconversion reactor vessel (e.g., an upstream bed of catalyst havingprimarily hydrotreating activity, for carrying out a desired degree ofdeoxygenation and a downstream bed of catalyst having primarilyhydrocracking activity, for reducing the molecular weight of thesubstantially fully deoxygenated hydrocarbon liquid). Otherwise, thediffering activities can be provided with multiple catalysts beingdispersed uniformly throughout a single catalyst bed, using a desiredmixing ratio of the multiple catalysts.

According to yet further embodiments, hydroconversion zone 375 maycomprise two or more hydroconversion reactor vessels, for examplepositioned in parallel or in series, and containing catalysts havingdiffering hydroprocessing activities and operating under differentconditions (e.g., differing pressures and/or temperatures). In aparticular embodiment, a first hydroconversion reactor vessel containinga catalyst having hydrotreating activity may be positioned in serieswith, and upstream of, a second hydroconversion reactor containing acatalyst having hydrocracking activity. Otherwise, these first andsecond hydroconversion reactors may be positioned in parallel. As willbe appreciated by those having skill in the art, and benefiting from theknowledge gained from the present disclosure, the use of differinghydroprocessing catalysts in one or more hydroconversion reactorvessels, arranged in various configurations, can be tailored to achievedesired characteristics of the substantially fully deoxygenatedhydrocarbon liquid, based on the properties of the particularbiomass-containing feedstock being processed.

A hydroconversion zone output 380 (e.g., the effluent or output from ahydroconversion reactor), containing a gaseous mixture includinghydrogen and other non-condensable gases (e.g., CO, CO₂, and/or CH₄) maybe cooled using hydroconversion zone outlet heat exchanger 385, whichmay utilize an external heat exchange medium (e.g., cooling water), anexchange medium internal to the integrated process (e.g., a feedstream), or a combination thereof. Cooling of hydroconversion zoneoutput 380 (e.g., the output from a single hydroconversion reactor, orotherwise two or more of such reactors, as described above) allows forphase separation of the components of this stream in a separation zonethat is included in system 111, namely separation zone 190 as describedabove with respect to FIG. 1. Other outputs from system 111, asdescribed above with respect to FIG. 1, are also provided, includinglines 161, 163, 164, and 167 comprising high purity carbon dioxide, foruse as CO₂ products as described herein. High purity hydrogen-containingstream 198 may be recycled to the hydropyrolysis reactor and/or optionalpre-reactor of system 510, and substantially fully deoxygenatedhydrocarbon liquid 195 may represent a further output of system 111.

The use of suitable pretreating steps described herein can be effectiveto upgrade other types of initial feedstocks, including MSW containinghigher levels of plastics, inert materials, and catalyst poisons. Thisis despite the failure of conventional processes to achieve satisfactoryresults and also despite the failure of the biomass pyrolysis andhydropyrolysis arts to even generally recognize or contemplate the useof pretreating steps, including those described herein, to upgrade verylow value materials (e.g., MSW or algae) and render them useful forprocessing in an integrated process comprising the further steps ofhydropyrolysis and hydroconversion.

Overall, aspects of the disclosure are associated with hydropyrolysisprocesses in which carbon dioxide (CO₂) products obtained from suchprocesses can serve as readily available inert gases for one or more,and preferably all, of the inertization functions described herein.Those having skill in the art, with the knowledge gained from thepresent disclosure, will recognize that various changes could be made inthese methods, without departing from the scope of the presentdisclosure. Mechanisms used to explain theoretical or observed phenomenaor results, shall be interpreted as illustrative only and not limitingin any way the scope of the appended claims. Although in the foregoingspecification this disclosure has been described in relation to certainpreferred embodiments thereof, and details have been set forth forpurpose of illustration, it will be apparent to those skilled in the artthat the disclosure is susceptible to additional embodiments and thatcertain of the details described herein can be varied considerablywithout departing from the basic principles of the disclosure. It shouldbe understood that the features of the disclosure are susceptible tomodification, alteration, changes or substitution without departingsignificantly from the spirit of the disclosure. For example, thedimensions, number, size and shape of the various components may bealtered to fit specific applications. Accordingly, the specificembodiments illustrated and described herein are for illustrativepurposes only, and not limiting of the disclosure as set forth in theappended claims.

We claim:
 1. A hydropyrolysis process, comprising: feeding both (i)hydrogen and (ii) a biomass-containing feedstock or a biomass-derivedfeedstock, to a hydropyrolysis reactor vessel containing a fluidized bedof a solid bed material, and producing a CO₂-containing vapor stream andat least one intermediate or final liquid product, wherein (i) solidstransport equipment is used for movement of the biomass-containingfeedstock or biomass-derived feedstock to or from the hydropyrolysisreactor vessel, or (ii) liquid containers are used for containing theintermediate or final liquid product, the process further comprising:using a CO₂ product, separated from the CO₂-containing vapor stream, forat least one inertization function of the hydropyrolysis process, theinertization function selected from the group consisting of operation ofthe solids transport equipment, blanketing of the liquid containers,drying of the biomass-containing feedstock or biomass-derived feedstock,conveying or separating the solid bed material, and combinationsthereof, wherein the CO₂ product has a combined concentration of H₂, CO,and hydrocarbons of less than about 10% by volume wherein theCO₂-containing vapor stream, from which the CO₂ product is separated, isselected from the group consisting of (i) a hydropyrolysis reactorvapor, obtained from a hydropyrolysis reactor output, (ii) ahydroconversion zone output, (iii) a pre-reactor vapor stream or apurified pre-reactor vapor stream, (iv) a regeneration effluent (v) ahydrogasification effluent, and combinations thereof.
 2. Thehydropyrolysis process of claim 1, wherein the hydropyrolysis reactoroutput is withdrawn from the hydropyrolysis reactor vessel; the processfurther comprising: feeding the hydropyrolysis reactor vapor, obtainedfrom the hydropyrolysis reactor output following the removal ofsubstantially all char particles, to a hydroconversion zone;hydroconverting at least a portion of the hydropyrolysis reactor vaporin the hydroconversion zone to obtain the hydroconversion zone output;recovering, by condensing a substantially fully deoxygenated hydrocarbonliquid from the hydroconversion zone output, a hydroconversion gaseousmixture; and introducing at least a portion of the hydroconversiongaseous mixture to a steam reformer that provides a net production ofCO₂, in addition to a net production of hydrogen, in a steam reformereffluent; wherein the CO₂-containing vapor stream is the steam reformereffluent, and the CO₂ product is recovered as a CO₂-enriched product ofseparation from the steam reformer effluent.
 3. The hydropyrolysisprocess of claim 1, wherein the CO₂ product, and any further CO₂products, separated from CO₂-containing vapor streams and used for anyinertization function selected from the group consisting of operation ofthe solids transport equipment, blanketing of the liquid containers,drying of the biomass-containing feedstock or biomass-derived feedstock,conveying or separating the solid bed material, and combinationsthereof, comprise CO₂ derived from renewable carbon of thebiomass-containing feedstock or biomass-derived feedstock.
 4. Thehydropyrolysis process of claim 3, wherein the CO₂ product, and anyfurther CO₂ products, separated from CO₂-containing vapor streams andused for any inertization function selected from the group consisting ofoperation of the solids transport equipment, blanketing of the liquidcontainers, drying of the biomass-containing feedstock orbiomass-derived feedstock, conveying or separating the solid bedmaterial, and combinations thereof, comprise CO₂ derived exclusivelyfrom renewable carbon of the biomass-containing feedstock orbiomass-derived feedstock.
 5. The hydropyrolysis process of claim 3,wherein the CO₂ product, and any further CO₂ products, separated fromCO₂-containing vapor streams and used for any inertization functionselected from the group consisting of operation of the solids transportequipment, blanketing of the liquid containers, drying of thebiomass-containing feedstock or biomass-derived feedstock, conveying orseparating the solid bed material, and combinations thereof, compriseCO₂ derived from at least one transformation of the biomass-containingfeedstock or biomass-derived feedstock, or of carbonaceous productsderived from the biomass-containing feedstock or biomass-derivedfeedstock, the transformation selected from the group consisting ofhydropyrolysis, devolatilization, combustion, and hydrogasification, andcombinations thereof.
 6. The hydropyrolysis process of claim 1, whereinthe inertization function is the operation of the solids transportequipment and comprises isolation or handling of particulate solids. 7.The hydropyrolysis process of claim 6, wherein the CO₂ product is usedfor the purging or pressurization of an environment within the solidstransport equipment, surrounding the particulate solids.
 8. Thehydropyrolysis process of claim 7, wherein the CO₂ product is used forthe purging of the environment within the solids transport equipment,surrounding the particulate solids, preceding or followed bypressurization of the environment with a flammable gas.
 9. Thehydropyrolysis process of claim 1, wherein the inertization function isthe operation of the solids transport equipment and comprisestemperature control or isolation of the solids transport equipment. 10.The hydropyrolysis process of claim 9, wherein the inertization functioncomprises the isolation of the solids transport equipment, wherein theCO₂ product is isolated between valves, opposite of which are gascompositions that, if mixed, would result in a flammable mixture. 11.The hydropyrolysis process of claim 10, wherein the CO₂ product isisolated at a pressure exceeding a pressure of at least one of the gascompositions, opposite one of the valves between which the CO₂ productis isolated.
 12. The hydropyrolysis process of claim 9, wherein theinertization function comprises temperature control of the solidstransport equipment, and wherein the solids transport equipmentcomprises a solids transfer screw.
 13. The hydropyrolysis process ofclaim 12, wherein the inertization function comprises flowing the CO₂product through a least a portion of the solids transfer screw.
 14. Thehydropyrolysis process of claim 1, wherein the biomass-derived feedstockis a pretreated feedstock, obtained after having been devolatilized orpartially hydropyrolyzed, or subjected to a physical classificationstep.